AVISTA CORP

Previous wording

Our business segments have not changed during the three months ended March 31, 2024. See the 2023 Form 10-K as well as “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

Current wording

Our business segments have not changed during the six months ended June 30, 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 months ended March 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 three and six months ended June 30 (dollars in thousands):

Previous wording

Net income for the three months ended March 31, 2024 increased compared to the three months ended March 31, 2023, primarily due to the effects of general rate cases and the timing impact of spreading less 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 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.

Previous wording

In mid-January 2024, our operations were impacted by the extreme cold experienced in the Pacific Northwest, which resulted in system load peaks that were higher than anticipated. This event highlighted the growing need for additional electric capacity in the region, and as a result we are taking the increase in demand related to more frequent severe weather events into account as we consider our resource adequacy and generation needs. The transition to clean energy (including the replacement of emitting generation assets with renewable energy which can be weather-reliant) and increasing electrification also factor into our integrated resource planning to ensure we have adequate resources to serve our customers. We are in the process of evaluating potential acceleration of our generation additions as compared to our most recent integrated resource plan.

Current 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.

Previous wording

During the first quarter of 2024, our region experienced low precipitation, resulting in low snowpack levels when compared to historical averages. These lower snowpack and precipitation levels had a negative impact on our hydroelectric generation resources during the quarter and are expected to continue to negatively impact forecast hydroelectric generation throughout the year. The decrease in hydroelectric generation will increase net power supply costs and result in us absorbing additional costs under the ERM in Washington. In the first quarter of 2024, we had a $6.0 million pre-tax expense under the ERM in Washington.

Current 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.

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 have been deferred and have been included in natural gas customer rates starting in April 2024. The resulting aggregate increase to customer bills is expected to be 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, 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.

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. 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.

Previous wording

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.

Current wording

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 wording

The WUTC has up to eleven months to review the general rate case filings and issue a decision.

Current 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.

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 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 wording

We expect to file a natural gas general rate case with the OPUC in the second half of 2024.

Current wording

We expect to file a natural gas general rate case with the OPUC in the fourth quarter of 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 assets of $15.1 million and $51.4 million as of March 31, 2024 and December 31, 2023, respectively.

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

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 $35.1 million and $37.6 million as of March 31, 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. Of the $35.1 million of deferred power costs as of March 31, 2024, $21.0 million is 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 $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.

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 assets of $5.3 million and $7.6 million as of March 31, 2024 and December 31, 2023, respectively. These deferred power cost balances represent amounts due from customers.

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

Previous wording

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 are adjusted so as to be based on the number of customers in certain customer rate classes 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. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the 2023 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Current wording

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 wording

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $12.3 million as of March 31, 2024 and $14.9 million as of December 31, 2023. Decoupling regulatory liabilities represent amounts due to customers.

Current 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.

Previous wording

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

Previous wording

Utility operating expenses increased due to increased benefits expense, as well as increased amortizations of previously deferred items now included in customer rates (resulting in no impact to net income).

Current 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).

Previous wording

Income tax was an expense in the first quarter of 2024, compared to a benefit in the first quarter of 2023. The change is primarily due to decreased tax customer credits, which offset the bill impact of rate increases included in our prior general rate cases, partially offset by the timing impact of spreading the decreased 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 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.

Previous wording

Electric utility revenues increased as a result of the effects of general rate cases (including a tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023), 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 and sales of fuel as part of our resource optimization activities. Natural gas utility revenues increased primarily due to increased wholesale revenues.

Previous wording

Electric utility resource costs increased primarily due to increased wholesale prices for our purchased power, as well as net amortizations and deferrals of power supply costs related to increased deferred costs in 2023 that are being amortized in 2024. Natural gas utility resource costs increased due to net amortizations and deferrals of costs related to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs. The increased net amortizations and deferrals were partially offset by decreased purchased natural gas costs.

Current wording

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 wording

The following discussion for Avista Utilities includes two financial measures 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 considered “non-GAAP financial measures”: electric utility margin and natural gas utility margin.

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 three months ended March 31 (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 June 30 (dollars in thousands):

Previous wording

Total electric revenues increased $109.6 million for the first quarter of 2024 as compared to the first quarter of 2023. The primary changes that occurred during the period were as follows:

Current 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:

Previous wording

a $33.9 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $26.7 million) and an increase in MWhs sold (increased revenues by $7.2 million).

Current 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).

Previous wording

Retail rates increased mainly due to the effects of our general rate cases, including the tranche of tax customer credits that were returned to customers as of the fourth quarter of 2023, which resulted in increased rates. The ERM surcharge to customers that commenced in July 2023 also increased retail rates.

Current wording

Retail rates increased mainly due to the effects of our general rate cases. The ERM surcharge to customers that commenced in July 2023 also increased retail rates.

Previous wording

Retail sales volumes increased primarily due to increased use by our residential and commercial customers. Compared to the first quarter of 2023, residential use per customer increased 3 percent and commercial use per customer increased 2 percent. Customer growth also contributed to the increased sales volumes.

Current wording

Retail sales volumes decreased primarily due to decreased use by our residential and commercial customers. Compared to the second quarter of 2023, residential use per customer decreased 7 percent and commercial use per customer decreased 4 percent primarily due to milder weather and decreased cooling loads. The decrease in use per customer was partially offset by customer growth.

Previous wording

a $1.9 million increase in electric decoupling revenue, resulting mostly from increased amortization of prior year rebate balances, partially offset by increased deferrals (due to higher use per customer).

Current wording

An $11.5 million increase in electric decoupling revenue, resulting mostly from increased current year deferrals (due to lower use per customer), as well as increased amortization of prior year rebate balances.

Previous wording

The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in utility natural gas operating revenues for the three months ended March 31 (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 June 30 (dollars in thousands):

Previous wording

a $13.8 million decrease in natural gas retail revenues (including industrial, which is included in other) due to decreased sales volumes (decreased revenues $14.1 million), partially offset by higher retail rates (increased revenues $0.3 million). The decrease in sales volumes was primarily due to decreased residential and commercial usage, resulting from milder winter weather. Compared to the first quarter of 2023, residential use per customer decreased 8 percent, and commercial firm use per customer decreased 5 percent. Heating degree days in Spokane decreased 3 percent from the first quarter of 2023, and were 4 percent below the historical average. Heating degree days in Medford decreased 18 percent compared to the first quarter of 2023, and were 10 percent below historical average.

Current 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.

Previous wording

a $20.1 million increase in natural gas decoupling revenue primarily due to current year surcharges to residential customers (due to lower use per customer) compared to rebates associated with higher usage in 2023, and decreased amortization of prior year surcharge balances.

Current wording

A $0.8 million decrease in natural gas decoupling revenue primarily due to current year surcharges to residential customers being lower than the prior year. This was partially offset by a decrease in amortization of prior year surcharge balances.

Previous wording

a $3.6 million increase 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 $3.6 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.

Previous wording

a $35.4 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $40.0 million), partially offset by a decrease in sales prices (decreased revenues $4.6 million). The fluctuation of volumes was due to increased opportunities to optimize our generation assets.

Current 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.

Previous wording

a $37.1 million increase in sales of fuel as part of thermal resource optimization activities, including associated financial hedging activities.

Current wording

A $37.1 million increase in sales of fuel as part of thermal generation resource optimization activities, including associated financial hedging activities, which includes net losses on derivative instruments resulting from commodity price volatility early in 2023.

Previous wording

a $17.2 million increase in wholesale natural gas revenues primarily due to financial losses associated with our hedging activities in the first quarter of 2023, which net 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 $14.9 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $18.5 million), partially offset by a decrease in sales volumes (decreased revenues $3.6 million). The increase in prices includes the impact of financial losses 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.

Previous wording

a $33.0 million increase in power purchased due to an increase in wholesale prices (increased costs $24.3 million) and an increase in the volume of power purchases (increased costs $8.7 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.

Current wording

A $31.8 million increase in purchased power costs due to an increase in wholesale prices (increased costs $34.2 million), partially offset by a decrease in the volume of power purchases (decreased costs $2.4 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 $24.2 million increase in fuel for generation. This is primarily due to financial gains recognized in the first quarter of 2023 associated with our hedging activities, which net with our physical purchases, as well as increased thermal generation in the first quarter of 2024 compared to 2023.

Current wording

A $14.2 million increase in fuel for generation primarily due to financial gains recognized in the first quarter of 2023 associated with our hedging activities, which net with our physical purchases, as well as increased thermal generation as compared to the prior year, because of higher sales volumes (retail and wholesale activities combined).

Previous wording

a $61.9 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $53.7 million), and a decrease in volumes (decreased costs $8.2 million). The decrease in volumes is primarily due to decreased retail usage.

Current wording

A $61.9 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $54.6 million), and a decrease in volumes (decreased costs $7.3 million). The decrease in the price of natural gas occurred primarily in the first quarter of 2024 due to milder weather (other than a specific January cold event).

Previous wording

a $79.0 million increase from net amortizations and deferrals of natural gas costs, primarily related to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs.

Current wording

A $85.9 million increase in other primarily related to a decrease in deferred costs during the period, as well as an increase in amortization of previously deferred costs. Deferred costs decreased during the period due to lower natural gas prices, mainly in the first quarter of 2024.

Previous wording

In the first quarter of 2024, we had a $6.0 million pre-tax expense under the ERM in Washington, compared to a $7.6 million pre-tax expense for the first quarter of 2023.

Current wording

In the first half of 2024, we had a $4.7 million pre-tax expense under the ERM in Washington, compared to a $6.5 million pre-tax expense for the first half of 2023.