# Avista Corp: Form 10-Q for the period ended Jun 30, 2025

- Company: [Avista Corp](/companies/ava.md) (CIK 104918)
- Form: 10-Q
- Filed: 2025-08-06
- Accepted by EDGAR: Aug 5, 2025, 23:48 ET
- Period: 2025-06-30
- Accession: 0000950170-25-103360
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/104918/000095017025103360/ava-20250630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/104918/000095017025103360/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-04-01 to 2025-06-30 | $411.0m | us-gaap:Revenues |
| Revenue | 6 months, 2025-01-01 to 2025-06-30 | $1.03bn | us-gaap:Revenues |
| Operating income | 3 months, 2025-04-01 to 2025-06-30 | $57.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2025-01-01 to 2025-06-30 | $182.0m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2025-04-01 to 2025-06-30 | $1.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2025-01-01 to 2025-06-30 | $13.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-04-01 to 2025-06-30 | $14.0m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2025-01-01 to 2025-06-30 | $93.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-04-01 to 2025-06-30 | $0.17 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2025-01-01 to 2025-06-30 | $1.15 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-04-01 to 2025-06-30 | $0.17 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2025-01-01 to 2025-06-30 | $1.15 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-04-01 to 2025-06-30 | 80,774,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2025-01-01 to 2025-06-30 | 80,542,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2025-01-01 to 2025-06-30 | $224.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 6 months, 2025-01-01 to 2025-06-30 | $246.0m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 6 months, 2025-01-01 to 2025-06-30 | $79.0m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2025-06-30 | $9.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-06-30 | $667.0m | us-gaap:AssetsCurrent |
| Total assets | at 2025-06-30 | $8.06bn | us-gaap:Assets |
| Current liabilities | at 2025-06-30 | $668.0m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-06-30 | $5.42bn | us-gaap:Liabilities |
| Short-term borrowings | at 2025-06-30 | $270.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2025-06-30 | $2.65bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 66,927 characters.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. Accordingly, this MD&A does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that are required to accompany financial statements for a full fiscal year and are contained in the Company's 2024 Form 10-K. Therefore, this MD&A should be read in conjunction with the Company's 2024 Form 10-K for full detail and analysis of the Company's financial condition, and results of operations, and a full discussion of trends and uncertainties that the Company faces.

### Business Segments

Our business segments have not changed during the six months ended June 30, 2025. See the 2024 Form 10-K as well as “Note 15 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

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

|  | Three months ended June 30, 2025 | 2024 | Six months ended June 30, 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: |
| Avista Utilities | $23 | $24 | $101 | $91 |
| AEL&P | 1 | 1 | 4 | 5 |
| Other non-reportable segment loss | (10) | (2) | (12) | (2) |
| Net income | $14 | $23 | $93 | $94 |

### Executive Overview

### Overall Results

Net income for the three and six months ended June 30, 2025 decreased compared to the three and six months ended June 30, 2024, primarily due to losses at our other businesses associated with lower valuations of certain investments in our portfolio. At Avista Utilities, the effects of our general rate cases have increased earnings in the first half of the year, partially offset by increased operating costs, depreciation and amortization expense and income tax expense.

More detailed explanations of the fluctuations in revenues and expenses are provided in the results of operations and business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this summary.

### Resource Adequacy and 2025 IRP

Our 2025 electric IRP was filed with the WUTC and IPUC in December 2024. While the IRP is subject to change from time to time due to changing circumstances, assumptions and projections, given the exit of Colstrip (222 MW) from our system by December 31, 2025 and the expected retirement of the Northeast combustion turbine (65 MW) in 2030, our preferred resource strategy includes the addition of approximately 490 MW of generating capacity by 2030 and a total addition of approximately 950 MW through 2035.

In May 2025, we issued a request for proposal to add energy and capacity of up to 415 MW for winter and 425 MW for summer to meet projected resource needs. As part of this request for proposal, we submitted self-build resource bids for consideration. Initial bids were submitted by the end of June 2025, and we expect to select a list of projects to move to the detailed proposal stage during the third quarter of 2025 and begin contract negotiations with final selected projects in the fourth quarter of 2025.

We also expect expanded transmission infrastructure will provide access to additional resources and improve reliability in our region. In November 2024, we signed a non-binding memorandum of understanding to join the North Plains Connector transmission line project, that plans to construct a transmission line from Bismarck, North Dakota to Colstrip, Montana.

For 2025, we expect generation at our hydro facilities to be approximately 85 percent of normal. To meet summer peak demands, we have used additional thermal generation or economic market purchases to offset the decrease in available hydroelectric resources.

### Tariffs on Imports

The President of the United States of America has imposed tariffs on certain imported goods and has announced plans to impose tariffs on others. The imposition of tariffs would impact the cost of other equipment and materials that are critical to our business, increasing capital and operating expenses, and could create supply chain disruptions. The tariffs have not had a material impact on our operations or financial performance to date. At this time, we are unable to reasonably estimate the effects of the tariffs, and have not made any adjustments to our capital or operating budget to account for increased costs resulting from tariffs.

We import a significant amount of natural gas from Canada, both to serve our retail natural gas customers and as fuel for electric generation. We do not expect these imports to be impacted by the current trade tariffs as they are covered by the U.S.-Mexico-Canada Agreement, but the future of trade tariffs on energy commodity imports is uncertain. The impact of an increase in resource costs on our results of operations (directly or indirectly resulting from tariffs) would be substantially mitigated by various deferral and recovery mechanisms (ERM, PCA, and PGAs), but there could be an immediate impact on our cash flow.

We are closely monitoring the impacts of tariffs and the potential impact they may have on our results of operations, financial condition and cash flows.

### U.S. Reconciliation Bill

In July 2025, the U.S. enacted a reconciliation bill commonly referred to as the One Big Beautiful Bill Act. We do not expect the bill to have a material impact on our financial results or annual effective tax rate for 2025. We continue to analyze provisions included in the bill, including the impact on various tax credits and the full expensing of domestic research and experimentation expenditures.

### Regulatory Lag

Regulatory “lag” is inherent in utility ratemaking; a result of the delay between the investment in utility plant and/or the increase in costs and the receipt of an order of a public utility commission authorizing an increase in rates sufficient to recover such investment or costs. Regulatory lag can be mitigated to some extent by the incorporation of reasonably expected forward-looking information into an authorization of increased rates. However, there is no protection against unexpected inflation and increased interest rates, as experienced in 2022 and 2023. Increased costs associated with tariffs as discussed above could result in additional regulatory lag. See “Regulatory Matters” for additional discussion of the general rate cases.

### Regulatory Matters

### General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We expect to continue to file for rate adjustments to:

- seek recovery of operating costs and capital investments, and
- seek the opportunity to earn reasonable returns as allowed by regulators.

With regard to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors including, but not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.

### Avista Utilities

### Washington General Rate Cases

#### 2024 General Rate Cases

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.

The approved rates within the orders are designed to increase annual electric base revenues by $12 million (or 2.0 percent), effective January 1, 2025 (Rate Year 1), and $44 million (or 7.5 percent) for Rate Year 2. The difference in approved rates for Rate Year 1 and those included in our original request of $77 million is primarily due to a $56 million decrease in power supply costs compared to those set forth in the original request, and also due to a lower approved return on equity than requested. The Rate Year 2 increase represents the effective increase to customers resulting from the $69 million approved in the order, partially offset by a $25 million decrease due to the expiration of a separate tariff in effect during Rate Year 1 to collect remaining Colstrip expenses by December 31, 2025 (see further discussion below).

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.

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.

The WUTC did not approve our request to modify the ERM under which differences between actual net power supply costs and the amount reflected in base retail customer rates are tracked. Based on our forecast energy commodity costs in 2025 and 2026, we expect actual net power supply costs to exceed the level included in base rates. We plan to continue to address how net power supply costs are set in base rates in future regulatory proceedings.

The Commission continued its support for important recovery mechanisms such as wildfire and insurance balancing accounts, and decoupling.

#### 2026 General Rate Cases

The Company expects to file its next multi-year electric and natural gas general rate cases in the first quarter of 2026.

#### Colstrip Tariff

In 2019, the Washington State Legislature passed the CETA, which, among other things, requires costs associated with coal-fired generation facilities to be removed from rates no later than December 31, 2025. The WUTC order approving the settlement of the 2022 general rate cases, required us to establish a tracker for our Colstrip-related costs, including operating and maintenance expense, depreciation and amortization expense, and a return on rate base. In October 2024, we filed a cost recovery tariff seeking to recover the costs associated with our ownership of Colstrip in 2025. In the filing, we requested an increase in annual Colstrip tariff revenues of $19 million – from $24 million in 2024 to $43 million in 2025, effective January 1, 2025. In its review, WUTC Staff raised three concerns related to (1) whether forecasted 2025 investments are allowed in rates; (2) whether the capital investment included in the filing will be used and useful for customers prior to the end of 2025; and (3) one major capital investment that will not be in service until 2027. In December 2024, the WUTC allowed our filed tariff to go into effect, but set the rates as subject to refund. The WUTC set the matter for adjudication in 2025, but also ordered us, WUTC Staff, and other interested parties to meet and resolve the issues. On March 6, 2025, the Commission held a prehearing conference for purposes of setting a procedural schedule. The issued schedule calls for a process that results in an Evidentiary Hearing on October 3, 2025, and a final order by the end of 2025.

### Idaho General Rate Cases

#### 2023 General Rate Cases

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.

The settlement was based on an ROE of 9.4 percent, with a common equity ratio of 50 percent, and an ROR of 7.19 percent.

#### 2025 General Rate Cases

In June 2025, we reached an all-party settlement agreement, which has been submitted to the IPUC for its consideration. If approved, new rates would be effective in September 2025 and September 2026.

The settlement is designed to increase annual base electric revenues by $20 million, or 6.3 percent, effective in September 2025, and $15 million, or 4.5 percent, effective in September 2026. For natural gas, the agreement is designed to increase annual base natural gas revenues by $5 million, or 9.2 percent, effective September 2025, and decrease annual base natural gas revenues by $0.2 million, or 0.4 percent, effective September 2026.

The settlement is based on an ROE of 9.6 percent with a common equity ratio of 50 percent and an ROR of 7.28 percent.

For base electric revenues, we originally requested an increase of $43 million (or 14.0 percent), effective September 1, 2025, and $18 million (or 5.0 percent), effective September 1, 2026. For base natural gas revenues, we originally requested an increase of $9 million (or 17.7 percent), effective September 1, 2025, and $1 million (or 1.7 percent), effective September 1, 2026. The lower base revenue agreed to by the parties is mainly due to a lower return on equity than we requested, as well as longer recovery periods for amortizations, a reduction in power supply expense versus filed, and a change in the law affecting the way property taxes are calculated and collected from customers.

### Oregon General Rate Case

#### 2024 General Rate Case

In May 2025, the OPUC approved the all-party settlement agreement designed to increase annual base revenues by $4 million, or 5.0 percent, effective in September 2025. The settlement was based on an ROE of 9.5 percent with a common equity ratio of 50 percent and an ROR of 7.22 percent.

To mitigate the overall impact of the revenue increases on customers, $5 million of tax customer credits will be accelerated and returned to customers over a three-year period.

#### Future Oregon General Rate Cases

In July 2025, the Governor of Oregon signed into law House Bill 3179 which modifies certain provisions as it relates to general rate case filings and cost recovery. The law, among other things, extends the length of time for the commission to suspend rates from nine to 10 months, does not allow residential rate increases of any kind between November 1 and March 31, does not allow new rates to take effect from a proceeding where the return on equity is at issue within 18 months of the prior rate effective date, authorizes securitization of “capital investments” that will cause rates to “rise by more than five percent” under specific circumstances, and calls for the OPUC to establish rules requiring utilities to establish a multiyear rate plan for rate revisions where a company’s return on equity is reviewed. Such rate plans must be no less than three years and no more than seven years in length.

### Avista Utilities

### Purchased Gas Adjustments, Power Cost Deferrals and Decoupling Mechanisms

See our 2024 Form 10-K for discussion of the various regulatory recovery mechanisms in each of our jurisdictions.

We received approval from the WUTC to recover $32 million of the ERM deferred surcharge balance in Washington over a two-year period starting July 1, 2025.

### Results of Operations - Overall

The following provides an overview of changes in our Condensed Consolidated Statements of Income and Comprehensive Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, and the other businesses) that follow this section.

The balances included below for utility operations reconcile to the Condensed Consolidated Statements of Income and Comprehensive Income.

### Three months ended June 30, 2025 compared to the three months ended June 30, 2024

The following graph shows the total change in net income for the second quarter of 2025 compared to the second quarter of 2024, as well as the factors that caused such change (dollars in millions):

Electric utility revenues increased as a result of the effects of general rate cases, and increased wholesale sales volumes. This was partially offset by decreased wholesale sale prices. Natural gas revenues decreased due to decreased rates associated with the PGAs (which do not impact utility margin or net income), as well as decreased sales volumes.

Utility resource costs decreased primarily due to net amortizations and deferrals of costs under our regulatory recovery mechanisms.

Utility operating expenses increased due to increased employee salaries and benefits costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.

Utility depreciation and amortization increased primarily due to additions to utility plant.

The decrease in earnings related to other is primarily due to net investment losses recorded in the second quarter of 2025 and increased taxes other than income taxes when compared to the second quarter of 2024.

### Six months ended June 30, 2025 compared to the six months ended June 30, 2024

The following graph shows the total change in net income for the six months ended June 30, 2025 compared to the six months ended June 30, 2024, as well as the factors that caused such change (dollars in millions):

Utility revenues increased as a result of the effects of general rate cases and customer and load growth. This was partially offset by decreased wholesale revenues associated with decreased sale prices, as well as decreased natural gas rates associated with PGA decreases, which do not impact utility margin or net income.

Electric utility resource costs decreased primarily due to decreased purchased power and fuel for generation, as well as increased deferrals of power supply costs and decreased amortizations of previously deferred costs. Natural gas utility resource costs decreased due to decreased commodity prices, as well as decreased amortizations of previously deferred PGA costs. These decreases were offset by an increase in the amortization of costs associated with the CCA that are being recovered from customers.

Utility operating expenses increased due to increased employee salaries and benefits costs, as well as thermal generation costs. In addition, net amortizations and deferrals associated with wildfire mitigation and insurance costs have increased, with corresponding increases to revenue which result in no impact to earnings.

Utility depreciation and amortization increased primarily due to additions to utility plant.

Income tax expense increased primarily due to the decrease in tax customer credits which offset the bill impact of rate increases included in our prior general rate cases. Income tax expense also increased due to increased pre-tax net income compared to the prior year. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The decrease in earnings related to other is primarily due to net investment losses recorded in the second quarter of 2025 and increased taxes other than income taxes compared to the first half of 2024.

### Non-GAAP Financial Measures

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

Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. Electric utility margin is electric operating revenues less electric resource costs, while natural gas utility margin is natural gas operating revenues less natural gas resource costs. The most directly comparable GAAP financial measure to electric and natural gas utility margin is utility operating revenues as presented in "Note 15 of the Notes to Condensed Consolidated Financial Statements."

The presentation of electric utility margin and natural gas utility margin is intended to enhance the understanding of operating performance. We use these measures internally and believe they provide useful information to investors in their analysis of how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. Changes in loads, as well as power and natural gas supply costs, are generally deferred and recovered from customers through regulatory accounting mechanisms. Accordingly, the analysis of utility margin generally excludes most of the change in revenue resulting from these regulatory mechanisms. We present electric and natural gas utility margin separately below for Avista Utilities since each business has different cost sources, cost recovery mechanisms and jurisdictions, so we believe separate analysis is beneficial. These measures are not intended to replace utility operating revenues as determined in accordance with GAAP as an indicator of operating performance. Reconciliations of operating revenues to utility margin are set forth below.

### Results of Operations - Avista Utilities

### Resource Optimization

We engage in resource optimization, which involves the selection from available energy resources to serve our load obligations and the use of these resources to capture economic value through wholesale market transactions, which is ultimately intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of electric capacity and energy and fuel for electric generation, purchases and sales of natural gas to optimize use of pipeline and storage capacity, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2024 Form 10-K for further discussion of our optimization activities.

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 are included 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).

### Three months ended June 30, 2025 compared to the three months ended June 30, 2024

### Customers

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended June 30, 2025 and 2024:

|  | Electric Customers 2025 | 2024 | Natural Gas Customers 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 375,572 | 369,978 | 345,685 | 342,691 |
| Commercial | 46,119 | 45,703 | 37,527 | 37,306 |
| Interruptible | — | — | 51 | 51 |
| Industrial | 1,171 | 1,177 | 184 | 184 |
| Public street and highway lighting | 802 | 763 | — | — |
| Total retail customers | 423,664 | 417,621 | 383,447 | 380,232 |

43

### Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended June 30, 2025 and 2024 (dollars in millions and MWhs in thousands):

(1) This balance includes public street and highway lighting, which is considered part of retail electric revenues.

Total electric operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2025 and 2024.

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 millions):

|  | Electric Decoupling Revenues 2025 | 2024 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $3 | $8 |
| Amortization of prior year decoupling deferrals (b) | — | 6 |
| Total electric decoupling revenue | $3 | $14 |

(a) Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b) Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $18 million for the second quarter of 2025 as compared to the second quarter of 2024. The primary changes that occurred during the period were as follows:

- A $33 million increase in retail electric revenue due to an increase in MWhs sold (increased revenues by $17 million) and an increase in retail rates (increased revenues by $16 million).
- Retail sales volumes increased primarily due to customer and load growth, including the effects of warmer weather. Cooling degree days in Spokane were 48 percent higher than normal during the second quarter of 2025, compared to 9 percent higher than normal in the second quarter of 2024. This was partially offset by a decrease in heating degree days, which were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.
- Retail rates increased mainly due to the effects of our general rate cases.
- A $2 million increase in wholesale electric revenues due to an increase in sales volumes (increased revenues $14 million), partially offset by a decrease in sales prices (decreased revenues $12 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
- An $11 million decrease in electric decoupling revenue, due to decreased amortizations of prior year rebate balances and decreased deferrals of surcharge balances due to increased loads compared to the second quarter of 2024.
- A $7 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended June 30, 2025 and 2024 (dollars in millions and therms in thousands):

(1) This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

Total natural gas operating revenues in the graph above include intracompany sales of $1 million for both the three months ended June 30, 2025 and 2024.

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 millions):

|  | Natural Gas Decoupling Revenues 2025 | 2024 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $9 | $3 |
| Amortization of prior year decoupling deferrals (b) | — | (1) |
| Total natural gas decoupling revenue | $9 | $2 |

(a) Positive amounts are increases in decoupling revenue in the current year and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year and will be rebated to customers in future years.

(b) Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total natural gas revenues decreased $10 million for the second quarter of 2025 as compared to the second quarter of 2024. The primary changes that occurred during the period were as follows:

- A $17 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $10 million) and decreased sales volumes (decreased revenues $7 million).
- Retail rates decreased mainly due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA.
- The decrease in sales volumes was primarily due to a 14 percent decrease in residential usage and a 10 percent decrease in commercial usage resulting from warmer weather. Heating degree days were 23 percent below normal in the second quarter of 2025, compared to 16 percent below normal in the second quarter of 2024.
- A $7 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year as a result of lower customer usage due to warmer weather.

### Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the three months ended June 30, 2025 and 2024 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $1 million for both the three months ended June 30, 2025 and 2024.

Total electric resource costs increased $1 million for the second quarter of 2025 as compared to the second quarter of 2024. The changes that occurred during the period were as follows:

- A $9 million increase in power purchased due to an increase in the volume of power purchases (increased costs $16 million), partially offset by a decrease in wholesale prices (decreased costs $7 million).
- A $6 million increase in fuel for generation. This was due to increases in fuel prices and thermal generation compared to the second quarter of 2024.
- A $14 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

The following graph presents Avista Utilities' natural gas resource costs for the three months ended June 30, 2025 and 2024 (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $1 million for both the three months ended June 30, 2025 and 2024.

Total natural gas resource costs decreased $16 million for the second quarter of 2025 as compared to the second quarter of 2024 due to the following:

- A $10 million decrease in natural gas purchased primarily due to a decrease in volumes consistent with a decrease in retail and wholesale sales volumes.
- A $6 million decrease in other costs primarily due to the decrease in amortizations of previously deferred costs under PGAs, which do not impact utility margin.

### Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 15 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended June 30, 2025 and 2024 (dollars in millions):

|  | Electric 2025 | 2024 | Natural Gas 2025 | 2024 | Intracompany 2025 | 2024 | Total 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $308 | $290 | $94 | $104 | $(2) | $(3) | $400 | $391 |
| Resource costs | 92 | 91 | 39 | 55 | (2) | (3) | 129 | 143 |
| Utility margin | $216 | $199 | $55 | $49 | $— | $— | $271 | $248 |

Electric utility margin increased $17 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $6 million primarily due to the effects of our general rate cases.

In the second quarter of 2025, we had a $1 million pre-tax expense under the ERM in Washington, compared to a $1 million pre-tax benefit for the second quarter of 2024.

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

### Six months ended June 30, 2025 compared to the six months ended June 30, 2024

### Utility Operating Revenues

#### Customers

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the six months ended June 30, 2025 and 2024:

|  | Electric Customers 2025 | 2024 | Natural Gas Customers 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 375,210 | 369,616 | 345,698 | 342,657 |
| Commercial | 45,848 | 45,923 | 37,462 | 37,415 |
| Interruptible | — | — | 52 | 51 |
| Industrial | 1,162 | 1,182 | 184 | 185 |
| Public street and highway lighting | 760 | 733 | — | — |
| Total retail customers | 422,980 | 417,454 | 383,396 | 380,308 |

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the six months ended June 30, 2025 and 2024 (dollars in millions and MWhs in thousands):

(1) This balance includes public street and highway lighting, which is considered part of retail electric revenues.

Total electric operating revenues in the graph above include intracompany sales of $1 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.

The following table presents the current year decoupling deferrals and the amortization of prior year decoupling deferrals reflected in utility electric operating revenues for the six months ended June 30 (dollars in millions):

|  | Electric Decoupling Revenues 2025 | 2024 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $(4) | $2 |
| Amortization of prior year decoupling deferrals (b) | — | 14 |
| Total electric decoupling revenue | $(4) | $16 |

(a) Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage and will be rebated to customers in future years.

(b) Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years due to higher customer usage and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total electric revenues increased $15 million for the first half of 2025 as compared to the first half of 2024. The primary changes that occurred during the period were as follows:

- A $73 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $43 million), and an increase in MWhs sold (increased revenues by $30 million).
- Retail rates increased mainly due to the effects of our general rate cases.
- Retail sales volumes increased primarily due to customer and load growth, including the effect of warmer weather. Cooling degree days were 48 percent above normal during the first half of 2025, compared to 9 percent above normal in the first half of 2024.
- A $33 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $46 million), partially offset by an increase in sales volumes (increased revenues $13 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
- A $20 million decrease in electric decoupling revenue, primarily due to decreased amortizations of prior year rebate balances, as well as current year rebate deferrals due to higher customer usage compared to surcharges deferred in 2024.
- A $8 million decrease in other electric revenues primarily resulting from decreased renewable energy credit revenues and transmission revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the six months ended June 30, 2025 and 2024 (dollars in millions and therms in thousands):

(1) This balance includes interruptible and industrial revenues, which are considered part of retail natural gas revenues.

Total natural gas operating revenues in the graph above include intracompany sales of $4 million and $5 million for the six months ended June 30, 2025 and 2024, respectively.

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

|  | Natural Gas Decoupling Revenues 2025 | 2024 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $10 | $4 |
| Amortization of prior year decoupling deferrals (b) | (2) | (1) |
| Total natural gas decoupling revenue | $8 | $3 |

(a) Positive amounts are increases in decoupling revenue in the current year due to lower customer usage and will be surcharged to customers in future years. Negative amounts are decreases in decoupling revenue in the current year due to higher customer usage and will be rebated to customers in future years.

(b) Positive amounts are increases in decoupling revenue in the current year and are related to the amortization of rebate balances that resulted in prior years due to higher customer usage and are being refunded to customers (causing a corresponding decrease in retail revenue from customers) in the current year. Negative amounts are decreases in decoupling revenue in the current year and are related to the amortization of surcharge balances that resulted in prior years due to lower customer usage and are being surcharged to customers (causing a corresponding increase in retail revenue from customers) in the current year.

Total natural gas revenues were consistent between the first half of 2025 as compared to the first half of 2024. The primary changes that occurred during the period were as follows:

- A $24 million decrease in natural gas retail revenues (including industrial, which is included in other) due to a decrease in retail rates (decreased revenues $26 million), partially offset by increased sales volumes (increased revenues $2 million). Retail rates decreased mainly due to PGA rate decreases (which do not impact utility margin), partially offset by the effects of our general rate cases and net rate increases associated with the CCA.
- A $5 million decrease in wholesale natural gas revenues due to a decrease in prices.
- A $5 million increase in natural gas decoupling revenues primarily due to increased surcharge deferrals in the current year.
- A $24 million increase in other gas revenues primarily due to the amortization of previously deferred revenues associated with the sale of CCA emissions credits. We amortize the deferred revenues as they are passed to customers through decreases in retail rates. The increase in other revenues was offset by decreased retail rates, resulting in no impact to utility margin.

### Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the six months ended June 30, 2025 and 2024 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $4 million and $5 million for the six months ended June 30, 2025 and 2024, respectively.

Total electric resource costs decreased $39 million for the first half of 2025 as compared to the first half of 2024. The changes that occurred during the period were as follows:

- An $18 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $42 million), partially offset by an increase in the volume of power purchases (increased costs $24 million). Prices during the first quarter of 2024 were elevated due to extreme cold temperatures in our region that created capacity constraints.
- A $5 million decrease in fuel for generation. This was primarily due to a decrease in fuel prices compared to the first half of 2024.
- A $16 million decrease in other electric resource costs, primarily related to an increase in deferred costs, as well as a decrease in the amortization of previously deferred costs. This was partially offset by increased costs related to our customer assistance payment programs (low-income rate assistance and demand side management).

The following graph presents Avista Utilities' natural gas resource costs for the six months ended June 30, 2025 and 2024 (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $1 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.

Total natural gas resource costs decreased $15 million for the first half of 2025 as compared to the first half of 2024 due to the following:

- A $28 million decrease in natural gas purchased primarily due to a decrease in the price of natural gas.
- A $13 million increase in other costs primarily related to the amortization of costs associated with the CCA that were recovered from customers, resulting in no impact to utility margin. This was partially offset by a decrease in amortizations of previously deferred costs under our PGAs.

### Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 16 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the six months ended June 30, 2025 and 2024 (dollars in millions):

|  | Electric 2025 | 2024 | Natural Gas 2025 | 2024 | Intracompany 2025 | 2024 | Total 2025 | 2024 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $671 | $656 | $338 | $338 | $(5) | $(8) | $1,004 | $986 |
| Resource costs | 218 | 257 | 172 | 187 | (5) | (8) | 385 | 436 |
| Utility margin | $453 | $399 | $166 | $151 | $— | $— | $619 | $550 |

Electric utility margin increased $54 million primarily due to the effects of general rate cases and customer growth. Natural gas utility margin increased $15 million, primarily due to the effects of general rate cases.

In the first half of 2025 we had a pre-tax expense of $9 million under the ERM in Washington, compared to a pre-tax expense of $5 million in the first half of 2024.

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the condensed consolidated financial statements but are included in the separate results for electric and natural gas presented above.

### Results of Operations - Alaska Electric Light and Power Company

Net income for AEL&P for the second quarter of 2025 was $1 million compared to $1 million for the second quarter of 2024. For the first half of 2025, net income for AEL&P was $4 million compared to $5 million for the first half of 2024.

### Results of Operations - Other Businesses

Our other businesses had a net loss of $10 million for the three months ended June 30, 2025 compared to $2 million for the three months ended June 30, 2024. For the first half of 2025, net loss at our other business was $12 million compared to $2 million for the first half of 2024.

The fluctuation in results is primarily related to higher net investment losses. Approximately 75 percent of our investment losses in the first half of 2025 were related to our investments in clean technology. That sector was negatively impacted by shifting public policy and sentiment, leading to decreased valuations of underlying holdings in these investments. Approximately 25 percent of our investment losses in the first half of 2025 were due to dilution of our ownership percentage resulting from issuances of new shares.

### Critical Accounting Policies and Estimates

The preparation of our condensed consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed consolidated financial statements and thus, actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2024 Form 10-K and have not changed materially.

### Liquidity and Capital Resources

### Overall Liquidity

Our sources of overall liquidity and the requirements for liquidity have not materially changed in the six months ended June 30, 2025. See the 2024 Form 10-K for further discussion.

As of June 30, 2025, we had $106 million of available liquidity under the Avista Corp. committed line of credit, $42 million of available liquidity under our letter of credit facility, and $9 million under the AEL&P committed line of credit. In July 2025, we issued long-term debt, using proceeds to repay borrowings that were outstanding as of June 30, 2025, which increased our available liquidity. With our existing credit facilities and the expected issuances of common stock and long-term debt within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.

### Review of Condensed Consolidated Cash Flow Statement

### Operating Activities

Net cash provided by operating activities was $224 million for the six months ended June 30, 2025, compared to $317 million for the six months ended June 30, 2024. A decrease of $81 million is associated with net power and natural gas cost deferrals and amortizations. In 2024, we recovered previously deferred costs from customers compared to returning deferred benefits in the first half of 2025. The change in other current assets also decreased operating cash flows by $44 million compared to the prior year, which is associated with increased balances for insurance proceeds receivable and prepayments. These decreases were partially offset by an increase of $44 million related to the change in other regulatory asset and liability balances, including the impacts of amortization and deferral activity associated with the CCA.

### Investing Activities

Net cash used in investing activities was $248 million for the six months ended June 30, 2025, compared to $254 million for the six months ended June 30, 2024. We paid $246 million for utility capital expenditures in 2025, compared to $251 million in 2024.

### Financing Activities

Net cash provided by financing activities was $3 million for the six months ended June 30, 2025, compared to $83 million used in financing activities for the six months ended June 30, 2024. We increased our short-term borrowings by $51 million in the six months ended June 30, 2025, compared to a decrease of $105 million in the six months ended June 30, 2024. We issued $84 million of long-term debt in the six months ended June 30, 2024, with no issuances of long-term debt in the first half of 2025. In addition, we issued $35 million of common stock and paid $79 million in dividends in the six months ended June 30, 2025, compared to issuing $18 million of common stock and paying $75 million in dividends in the first half of 2024.

### Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of June 30, 2025 and December 31, 2024 (dollars in millions):

|  | June 30, 2025 Amount | Percent of total | December 31, 2024 Amount | Percent of total |
| --- | ---: | ---: | ---: | ---: |
| Current portion of long-term debt and leases | $8 | 0.1% | $8 | 0.1% |
| Short-term borrowings | 270 | 4.6% | 354 | 6.2% |
| Long-term debt to affiliated trusts | 52 | 0.9% | 52 | 0.9% |
| Long-term debt and leases | 2,846 | 49.0% | 2,711 | 47.4% |
| Total debt | 3,176 | 54.6% | 3,125 | 54.7% |
| Total shareholders’ equity | 2,645 | 45.4% | 2,591 | 45.3% |
| Total | $5,821 | 100.0% | $5,716 | 100.0% |

Our shareholders’ equity increased $54 million during the first half of 2025 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.

### Short Term Borrowings

#### Avista Corp.

Avista Corp. has a committed line of credit with various financial institutions in the total amount of $500 million with an expiration date of June 2029. We may request that the lenders extend their commitments for an additional one-year period (subject to customary conditions).

We also have a continuing letter of credit agreement in the aggregate amount of $50 million. Either party may terminate the agreement at any time.

The following table summarizes the balances outstanding and available liquidity as of June 30, 2025 (dollars in millions):

|  | Amount of Facility | Borrowings Outstanding (1) | Letters of Credit Outstanding (2) | Available Liquidity |
| --- | ---: | ---: | ---: | ---: |
| Line of Credit expiring June 2029 | $500 | $389 | $5 | $106 |
| Letter of Credit Facility | 50 | N/A | 8 | 42 |
| Total | $550 | $389 | $13 | $148 |

(1) As of June 30, 2025, there was $389 million outstanding under the committed line of credit; however, $270 million was classified as short-term borrowings and $119 million was classified as long-term on the Condensed Consolidated Balance Sheet due to the Company's intention to refinance such amount on a long-term basis. The amount classified as long-term debt was refinanced through the issuance and sale of first mortgage bonds in July 2025.

(2) Letters of credit are not reflected on the Condensed Consolidated Balance Sheets. If a letter of credit were drawn upon by the holder, we would have an immediate obligation to reimburse the bank that issued that letter.

The Avista Corp. credit facilities contain customary covenant and default provisions, including a change in control (as defined in the agreements). The events of default under each of the credit facilities also include a cross default from other indebtedness (as defined) and, in the case of the letter of credit agreement, other obligations. The committed line of credit agreement also includes a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of June 30, 2025, we complied with this covenant with a ratio of 54.6 percent.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s lines of credit were as follows as of and for the six months ended June 30 (dollars in millions):

| $500 million line of credit, expiring June 2029 | 2025 | 2024 |
| --- | ---: | ---: |
| Maximum balance outstanding during the period | $400 | $349 |
| Average balance outstanding during the period | $312 | $260 |
| Average interest rate during the period | 5.44% | 6.46% |
| Average interest rate at end of the period | 5.42% | 6.55% |

#### AEL&P

AEL&P has a $25 million committed line of credit that expires in June 2028. As of June 30, 2025, there was $16 million outstanding under this committed line of credit, and $9 million of available liquidity. As of June 30, 2025, the $16 million outstanding under the committed line of credit was classified as long-term on the Condensed Consolidated Balance Sheet due to AEL&P's intention to refinance such amount on a long-term basis. The borrowings were refinanced through entering a term loan agreement in July 2025.

The AEL&P credit facility contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of June 30, 2025, AEL&P complied with this covenant with a ratio of 49.3 percent.

As of June 30, 2025, Avista Corp. and its subsidiaries complied with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit.

See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding our short-term borrowing arrangements.

### Liquidity Expectations

During July 2025, we issued and sold $120 million of long-term debt, and AEL&P entered into a term loan agreement for $20 million. We do not expect additional debt issuances in 2025. We expect to issue $80 million of common stock in 2025 (including $35 million issued through June 30, 2025).

### Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure, and expect Avista Utilities' capital expenditures to be about $525 million in 2025. We expect Avista Utilities' capital expenditures to be $575 million in 2026, and $600 million in 2027. These planned capital expenditures are subject to continuing review and adjustments, and do not include expenditures for additional generation or transmission facilities that are contemplated in our IRP but have not been specifically identified and approved. See the 2024 Form 10-K for further information on our expected capital expenditures.

We expect AEL&P capital expenditures to be $21 million in 2025.

### Pension Plan

In the six months ended June 30, 2025, we contributed $7 million to the pension plan and expect contributions to total $10 million in 2025. We expect to contribute a total of $40 million to the pension plan in the period 2026 through 2029, with an annual contribution of $10 million.

The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular, the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above.

See "Note 6 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding the pension plan.

### Environmental Issues and Contingencies

Our environmental issues and contingencies disclosures have not materially changed during the six months ended June 30, 2025 except as follows:

### Washington State Building Codes

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code requiring most new commercial buildings and large multifamily buildings to install all-electric space heating. An amendment to the code allows for natural gas to supplement electric heat pumps. In addition, in November 2022, the SBCC approved new building and energy codes for residential housing, requiring new residential buildings in Washington to use electricity as the primary heat source. These building codes have been subject to various legal challenges, as discussed in our 2024 Form 10-K.

In November 2024, Washington voters approved Initiative 2066, which would prohibit state and local governments from restricting access to natural gas, prohibit the SBCC from discouraging or penalizing the use of natural gas, and prohibit the WUTC from approving any multi-year rate plan that requires or incentivizes natural gas companies to terminate or limit natural gas service. In March 2025, a Washington state court held that the Initiative violates the “single subject rule” and is invalid. That decision has been appealed and the appeal remains pending.

Over time, the building code changes would likely have an adverse impact on our natural gas business and natural gas customers but could also have a positive effect on our electric business. While we are in the process of studying the implications of the changes on our business, at this time, we are not able to quantify the likely net effect, positive or negative, on our overall results of operations over the long term. However, the changes would clearly require that additional generating capacity be available to utilities and customers in Washington state.

### EPA Regulations for Power Plants

On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities as further described in our 2024 Form 10-K.

These rules potentially fall within the scope of a number of Presidential executive orders that have been issued, which are discussed in more detail under “2025 Presidential Executive Action” below. In addition, a substantial number of legal challenges have been filed regarding these rules, and those lawsuits remain pending. At the same time, we continue to analyze each of these rules to assess the impact, if any, they may have on our existing generating units. To the extent there are any additional costs associated with compliance, we will seek to recover those costs through the ratemaking process.

### 2025 Presidential Executive Action

Since taking office, the U.S. President's Administration has issued a multitude of Executive Orders directed towards national energy resources and development. These include actions to:

- immediately pause the disbursement of funds appropriated through the Inflation Reduction Act of 2022 or the Infrastructure and Jobs Act;
- require agency review of regulations, programs and executive orders that might limit the development or use of domestic energy resources such as oil, natural gas, coal and nuclear;
- revoke the prior Administration’s Executive Orders on climate policy;
- require agency review of regulations, programs and executive orders that limit consumer choice for vehicles and appliances;
- require review of the 2009 EPA endangerment finding for greenhouse gases under the Clean Air Act;
- direct the EPA to revise or eliminate the use of a social cost of carbon in federal decision-making;
- declare a national emergency to expedite the development of energy infrastructure;
- direct emergency action under section 202(c) of the Federal Power Act by streamlining and expediting the approval of orders allowing electric generation resources to operate at maximum capacity during times of anticipated grid failure;
- grant a two-year exemption from the EPA’s MATS rule for certain stationary sources, including Colstrip, citing the lack of commercially viable emissions-control technology needed to meet the 2027 compliance deadline; and
- directs the United States Attorney General to identify and act against state and local laws that burden domestic energy production and may be unconstitutional, preempted by federal law, or otherwise unlawful, particularly those tied to climate change, carbon penalties or carbon cap and trade programs, and Environmental, Social and Governance policies.

Some of these Executive Orders are the subject of legal challenges and/or are the subject of federal court injunctions, either in whole or in part. We are assessing potential impacts, opportunities and risks that may arise from these and other executive actions that may be taken by the Administration. To the extent that any action taken by the Administration results in increased costs for our business, we will seek to recover those costs through the rate-making process.

See the 2024 Form 10-K for further discussion of our environmental issues and contingencies.

### Enterprise Risk Management

The material risks to our businesses, and our mitigation process and procedures to address these risks, were discussed in our 2024 Form 10-K and have not materially changed during the six months ended June 30, 2025. See the 2024 Form 10-K.

### Financial Risk

Our financial risks have not materially changed during the six months ended June 30, 2025. Refer to the 2024 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2024.

#### Interest Rate Risk

We use a variety of techniques to manage our interest rate risks. We have an interest rate risk policy and a policy to limit our variable rate exposures to a percentage of total capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. See "Note 5 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of June 30, 2025 and December 31, 2024 and the amount of additional collateral we would have to post in certain circumstances.

#### Credit Risk

As of June 30, 2025, we had cash deposited as collateral of $25 million and letters of credit of $8 million outstanding related to our energy contracts. Price movements and/or a downgrade in our credit ratings or other established credit criteria could impact further the amount of collateral required. See “Credit Ratings” in the 2024 Form 10-K for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at June 30, 2025 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (dollars in millions):

|  | June 30, 2025 |
| --- | ---: |
| Additional collateral taking into account contractual thresholds | $19 |
| Additional collateral without contractual thresholds | 36 |

60

### Energy Commodity Risk

Our energy commodity risks have not materially changed during the six months ended June 30, 2025. See the 2024 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of June 30, 2025 expected to be delivered in each respective year (dollars in millions). There are no expected deliveries of energy commodity derivatives after 2028.

| Year | Purchases Electric Derivatives Physical (1) | Financial (1) | Gas Derivatives Physical (1) | Financial (1) | Sales Electric Derivatives Physical (1) | Financial (1) | Gas Derivatives Physical (1) | Financial (1) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Remainder 2025 | $— | $— | $(11) | $(7) | $1 | $(1) | $(2) | $— |
| 2026 | — | — | (6) | (2) | — | (3) | (6) | — |
| 2027 | — | — | (1) | (1) | — | — | (4) | — |
| 2028 | — | — | — | — | — | — | (3) | — |

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2024 expected to be delivered in each respective year (dollars in millions). There were no expected deliveries of energy commodity derivatives after 2027.

| Year | Purchases Electric Derivatives Physical (1) | Financial (1) | Gas Derivatives Physical (1) | Financial (1) | Sales Electric Derivatives Physical (1) | Financial (1) | Gas Derivatives Physical (1) | Financial (1) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2025 | $— | $— | $(23) | $(19) | $10 | $7 | $(3) | $— |
| 2026 | — | — | (9) | (3) | — | — | — | — |
| 2027 | — | — | (2) | — | — | — | — | — |

(1) Physical transactions represent commodity transactions where we will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of the benefit or cost but with no physical delivery of the commodity, such as futures, swap derivatives, options, or forward contracts.

The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers.

### Future Resource Needs

#### 2025 Natural Gas Integrated Resource Plan (IRP)

In March 2025, we filed our 2025 Natural Gas IRP with the WUTC, the IPUC and the OPUC. The IRP outlines a preferred resource portfolio which is designed to meet the forecast for system energy demand and comply with emissions legislation over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.

Highlights of the 2025 Natural Gas IRP include the following expectations and/or assumptions:

- Customer usage estimates are increasingly difficult to forecast due to the variety of rules and codes passed by Oregon, Washington, and federal administrations. The Washington building codes are assumed to remain in effect.
- The IRP focuses on greenhouse gas emissions compliance program constraints of the CCA in Washington and the CPP in Oregon.
- The Oregon preferred resource strategy assumes the utilization of renewable natural gas resources and energy efficiency investments, as well as emissions reductions after 2029 and carbon capture starting in 2035 as the primary tools to meet customer energy needs and comply with the CPP program requirements.
- The Washington preferred resource strategy assumes the utilization of conventional natural gas and energy efficiency, along with allowance offsets that are provided by the state or purchased by the Company and emissions reductions to meet the requirements under the CCA.
- The state of Idaho currently does not have any greenhouse gas emissions reduction policies, and as such the preferred resource strategy continues to utilize natural gas from existing access to supply basins, and our existing storage.

## Market risk

As filed, 232 characters.

The information required by this item is set forth in the Enterprise Risk Management section of "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference.

## Controls and procedures

As filed, 1,931 characters.

### Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of June 30, 2025.

There have been no changes in the Company's internal control over financial reporting that occurred during the second quarter of 2025 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

## Risk factors

As filed, 1,506 characters.

Refer to the 2024 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2024 Form 10-K. However, due to recent legislation and changes in public sentiment, we are providing the following enhanced discussion of risks inherent in our investments:

As discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements under “Equity Investments” and in Management’s Discussion and Analysis of Financial Condition and Results of Operations under “Executive Overview – Overall Results” and “Results of Operations – Other Businesses”, the fair values of our respective equity investments fluctuate from period to period, and such changes in fair value directly affect our net income. While we make these investments after prudent analysis and with the expectation of eventual financial gains, there is no assurance that these investments will ultimately be successful. However, it is likely that the value of these investments will continue to fluctuate as the businesses continue to mature, causing corresponding changes in our net income. In addition, the risks faced by these businesses differ from the risks faced by our utility operations.

Filed Aug 6, 2025.
Source: SEC EDGAR, the filing index for accession 0000950170-25-103360. Last ingested by Listed: Oct 24, 2026, 14:55 ET. No prices; not investment advice.