# Avista Corp: Form 10-Q for the period ended Sep 30, 2024

- Company: [Avista Corp](/companies/ava.md) (CIK 104918)
- Form: 10-Q
- Filed: 2024-11-06
- Accepted by EDGAR: Nov 6, 2024, 00:29 ET
- Period: 2024-09-30
- Accession: 0000950170-24-121737
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/104918/000095017024121737/ava-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/104918/000095017024121737/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-07-01 to 2024-09-30 | $393.7m | us-gaap:Revenues |
| Revenue | 9 months, 2024-01-01 to 2024-09-30 | $1.41bn | us-gaap:Revenues |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | $48.8m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | $204.1m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | −$478.0k | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | $2.3m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | $18.5m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | $112.8m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.23 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | $1.44 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.23 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | $1.44 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 78,968,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 78,545,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $444.2m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2024-01-01 to 2024-09-30 | $405.4m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 9 months, 2024-01-01 to 2024-09-30 | $112.5m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2024-09-30 | $9.1m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $525.1m | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $7.78bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $700.2m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-09-30 | $5.25bn | us-gaap:Liabilities |
| Current portion of debt | at 2024-09-30 | $15.0m | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2024-09-30 | $287.3m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2024-09-30 | $2.53bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 75,196 characters.

Management’s Discussion and Analysis of Financial Condition and Results of Operations was prepared in accordance with the SEC’s Regulation S-K for interim financial information and with the instructions to Form 10-Q. This Management’s Discussion and Analysis of Financial Condition and Results of Operations does not contain the full detail or analysis, or the full discussion of trends and uncertainties, that would accompany financial statements for a full fiscal year; therefore, it should be read in conjunction with the Company's 2023 Form 10-K.

### Business Segments

Our business segments have not changed during the nine months ended September 30, 2024. See the 2023 Form 10-K as well as “Note 16 of the Notes to Condensed Consolidated Financial Statements” for further information regarding our business segments.

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

|  | Three months ended September 30, 2024 | 2023 | Nine months ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Avista Utilities | $19,803 | $13,498 | $111,246 | $83,935 |
| AEL&P | 41 | 288 | 5,061 | 5,689 |
| Other | (1,357) | 930 | (3,467) | (2,579) |
| Net income | $18,487 | $14,716 | $112,840 | $87,045 |

### Executive Overview

### Overall Results

Net income for the three and nine months ended September 30, 2024 increased compared to the three and nine months ended September 30, 2023, primarily due to the effects of general rate cases and tax customer credits. These increases in earnings were partially offset by expected increases in operating expenses, depreciation and amortization expense, taxes other than income tax and interest expense.

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

#### Peak Load Requirements

Extreme weather events, both in summer and winter, have recently occurred in the Pacific Northwest. These events have resulted in system load peaks that were higher than anticipated. Historically, we have had excess capacity as compared to peak load, but during some extreme events we have had to purchase short-term energy from the wholesale market to meet demand when our energy resources were not operating at full capacity or were otherwise unavailable. These weather events have highlighted the growing need for additional generating capacity both on our system and in the Pacific Northwest region. Accordingly, we are taking the increased peaks in demand into account as we consider our resource adequacy and generation requirements.

#### Annual Energy Requirements

The transition to clean energy (including the replacement of emitting facilities with non-emitting facilities, which are impacted by conditions outside of our control), and electrification, combined with expected load growth, factor into the analysis of the need for additional generation. As a result, we expect additional generating capacity will be needed earlier than reflected in our 2023 integrated resource plan (IRP).

#### 2025 IRP

A draft IRP, reflecting the accelerated addition of generating resources, was submitted to the WUTC and IPUC in October 2024, and we plan to file the final IRP in January 2025. While the draft 2025 IRP is, and even the final 2025 IRP will be, subject to change from time to time due to changing circumstances, assumptions and projections, given the exit of Colstrip (222 MW) from our system by December 31, 2025 and the expected retirement of the Northeast combustion turbine (64.8 MW) in 2030, we see the need for the addition of approximately 490 MW of generating capacity by 2030 and a total of approximately 950 MW through 2035. We believe the additional capacity would likely consist of primarily of wind resources and a natural gas combustion turbine. The new capacity would likely be a combination of resources owned by the Company and resources committed under PPAs, to be determined on a case-by-case basis depending upon financial, tax and regulatory considerations.

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

### 2024 Hydroelectric Generation and Snowpack Conditions

During 2024, our region experienced low precipitation, resulting in low snowpack levels and streamflows when compared to historical averages. This had a negative impact on our hydroelectric generation resources. Lower hydroelectric generation increased net power supply costs and resulted in us absorbing additional costs under the ERM in Washington. In the nine months ended September 30, 2024, we had a $7.8 million pre-tax expense under the ERM in Washington.

### Washington Climate Commitment Act (CCA)

Effective January 1, 2023, the CCA went into effect in the State of Washington, requiring us to secure carbon allowances to cover our carbon emissions over a certain amount each year. Costs associated with the CCA are being deferred and are included in Washington natural gas customer rates starting in April 2024. The resulting aggregate increase to customer bills was approximately 3.7 percent over a one year period, and impacts customers differently based on revenue class, income level, and meter connection date. We have proposed an additional customer bill increase to recover costs associated with the CCA of 9.1 percent to become effective in November 2024, subject to WUTC approval.

Costs associated with the CCA related to our electric operations are deferred and included in the ERM for Washington customers. Amounts allocated to Idaho are not approved for recovery from customers. See "Note 15 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the CCA costs associated with our electric operations and impacts on our financial results.

### 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. 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.

### 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 that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items.

### Avista Utilities

### Washington General Rate Cases

#### 2024 General Rate Cases

On January 18, 2024, we filed multi-year electric and natural gas general rate cases with the WUTC. If approved, new rates would be effective in December 2024 and December 2025.

The proposed electric and natural gas revenue increase requests were based on a 10.4 percent ROE with a common equity ratio of 48.5 percent and an ROR of 7.61 percent. Increasing power supply costs, operating and maintenance costs, and ongoing capital investments (including clean energy hydroelectric projects, continued investment in the wildfire resiliency plan, replacement of natural gas distribution pipe and technology upgrades) were the main drivers of proposed increases.

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.

In August 2024, we filed rebuttal testimony, which updated our request as follows:

- The proposed rates are designed to increase annual base electric revenues by $42.9 million, or 7.3 percent, effective in December 2024, and $44.9 million (representing our $69.3 million requested increase partially offset by a $24.4 million reduction in customer rates resulting from a revenue reduction in a separate Colstrip tariff) or 10.9 percent, effective in December 2025.
- For the December 2025 electric increase, the effect of increasing base power supply costs (primarily to make up for the removal of Colstrip from our generation portfolio) accounts for $54.2 million of our overall $69.3 million request.
- The proposed rates are designed to increase annual base natural gas revenues by $16.8 million, or 13.2 percent, effective December 2024, and $4.0 million, or 2.8 percent, effective December 2025.

Additionally, we are proposing changes to the ERM. Under the present construct, the ERM consists of a $4 million deadband, and then an asymmetric sharing band between $4 million and $10 million. All costs above $10 million are shared on a 90 percent customer, 10 percent company basis. As part of this rate case on rebuttal, we are proposing to have a $2 million deadband in the rebate direction, a $2.5 million deadband in the surcharge direction, and all other costs shared on a 90 percent customer, 10 percent company basis.

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

### Idaho General Rate Cases

#### 2023 General Rate Cases

In February 2023, we filed multi-year electric and natural gas general rate cases with the IPUC. In August 2023, the IPUC approved the multi-party settlement agreement designed to increase annual base electric revenues by $22.1 million, or 8.0 percent, effective in September 2023, and $4.3 million, or 1.4 percent, effective in September 2024. The agreement was designed to increase annual base natural gas revenues by $1.3 million, or 2.7 percent, effective in September 2023, and a negligible increase effective in September 2024.

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

We expect to file electric and natural gas general rate cases with the IPUC in the first quarter of 2025.

### Oregon General Rate Case

#### 2023 General Rate Case

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.

#### 2024 General Rate Case

In November 2024, we filed a general rate case with the OPUC, which is designed to increase overall revenue by $7.8 million, or 9.2 percent, effective September 1, 2025. The case is based on a proposed ROR of 7.67 percent with a common equity ratio of 50 percent and an ROE of 10.4 percent. Ongoing capital infrastructure investment (including replacement and expansion of natural gas distribution pipe and technology) is the main driver of the proposed increase. The OPUC has up to ten months to review the general rate case filing and issue a decision.

### AEL&P

### Alaska General Rate Case

In August 2023, the RCA issued a final order related to AEL&P’s electric general rate case, which was originally filed in July 2022.

The order reflects an 11.45 percent ROE, a common equity ratio of 60.7 percent, and an ROR of 8.79 percent. The order also results in an approved base electric revenue increase of 6.0 percent (designed to increase annual electric revenues by $2.1 million), and also makes non-refundable the interim rate increase of 4.5 percent that was approved by the RCA in August 2022 and took effect in September 2022. The final increase to rates was effective in October 2023.

AEL&P is required to file its next general rate case by August 2027.

### Avista Utilities

### Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with little to no change in utility margin (operating revenues less resource costs) or net income. In Washington and Idaho, all costs under the PGAs are passed through to customers. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply to the extent not hedged. Total net deferred natural gas costs among all jurisdictions were liabilities of $9.8 million as of

September 30, 2024 and assets of $51.4 million as of December 31, 2023. This change primarily represents the collection of previously deferred natural gas costs and a decrease in natural gas prices.

### Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used in Washington to track certain differences between actual power supply costs, net of the margin on wholesale sales of energy and sales of fuel, and the amount included in base retail rates for our customers. See the 2023 Form 10-K for a full discussion of the mechanics of the ERM and the various customer/Company sharing bands. Total net deferred power costs under the ERM were assets of $35.8 million and $37.6 million as of September 30, 2024 and December 31, 2023, respectively. These deferred power cost balances represent amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in either the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to return the balance to customers or recover the balance from customers, as the case may be. As of September 30, 2024, $13.1 million of the $35.8 million is still being recovered through a rate surcharge to customers over a two-year period, effective July 1, 2023, as approved by the WUTC.

The PCA mechanism in Idaho allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference (positive or negative) between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a liability of $12.5 million and an asset of $7.6 million as of September 30, 2024 and December 31, 2023, respectively.

### Decoupling Mechanisms

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.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory assets of $8.0 million as of September 30, 2024 and regulatory liabilities of $14.9 million as of December 31, 2023. Decoupling regulatory assets represent amounts due from customers. Decoupling regulatory liabilities represent amounts due to customers.

See "Results of Operations - Avista Utilities" for further discussion of the amounts recorded to operating revenues in 2024 and 2023 related to the decoupling mechanisms.

### Results of Operations - Overall

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

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

### Three months ended September 30, 2024 compared to the three months ended September 30, 2023

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

Electric utility revenues increased as a result of the effects of general rate cases and customer growth, partially offset by decreased wholesale revenues as part of our resource optimization activities. Natural gas utility revenues decreased slightly primarily due to decreased wholesale revenues.

Utility resource costs decreased primarily due to decreased commodity prices. These were partially offset by increased purchased volumes of power and natural gas, as well as increased amortizations of previously deferred costs compared to the third quarter of 2023.

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

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

Interest expense increased primarily due to increased borrowings outstanding and increased interest rates compared to 2023.

Income tax benefits decreased primarily due to the decrease in tax customer credits which offset a portion of the bill impact of rate increases included in our prior general rate cases. This decrease in tax customer credits was partially offset by the timing impact of spreading these fewer available credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The decrease in earnings related to other is primarily due to increased taxes other than income tax, as well as net investment losses recorded in the third quarter of 2024 compared to net investment gains in 2023.

### Nine months ended September 30, 2024 compared to the nine months ended September 30, 2023

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

Electric utility revenues increased as a result of the effects of general rate cases, the ERM surcharge to customers, and increased wholesale sales volumes and sales of fuel as part of our resource optimization activities. This was partially offset by decreased wholesale sale prices. Natural gas utility revenues increased primarily due to increased wholesale revenues and additional decoupling revenues associated with surcharge deferrals from lower customer use.

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.

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

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

Interest expense increased primarily due to increased borrowings outstanding during the period and increased interest rates compared to 2023.

Income tax was an expense for the nine months ended September 30, 2024, compared to a benefit for the nine months ended September 30, 2023. The change is primarily due to the decrease in tax customer credits offsetting the bill impact of rate increases included in our prior general rate cases. This decrease in tax customer credits was partially offset by the timing impact of spreading these fewer available credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 7 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

### 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 16 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 intended to lower net power and natural gas supply costs. Our resource optimization transactions can take the form of physical sales and purchases of energy (natural gas or electricity), electric capacity and fuel for electric generation, as well as financial derivative contracts related to capacity, energy, fuel and fuel transportation. See our 2023 Form 10-K for further discussion of our optimization activities.

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 September 30, 2024 compared to the three months ended September 30, 2023

### Utility Operating Revenues

#### Customers

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

|  | Electric Customers 2024 | 2023 | Natural Gas Customers 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 371,427 | 366,053 | 343,101 | 339,843 |
| Commercial | 45,564 | 45,153 | 37,215 | 36,899 |
| Interruptible | — | — | 51 | 51 |
| Industrial | 1,168 | 1,177 | 184 | 185 |
| Public street and highway lighting | 740 | 700 | — | — |
| Total retail customers | 418,899 | 413,083 | 380,551 | 376,978 |

48

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended September 30, 2024 and 2023 (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 $0.5 million and $1.2 million for the three months ended September 30, 2024 and 2023, 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 three months ended September 30 (dollars in thousands):

|  | Electric Decoupling Revenues 2024 | 2023 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $(1,871) | $(2,312) |
| Amortization of prior year decoupling deferrals (b) | 3,702 | 4,121 |
| Total electric decoupling revenue | $1,831 | $1,809 |

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

- A $29.6 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $22.0 million), and an increase in MWhs sold (increased revenues by $7.6 million).
- Retail rates increased mainly due to the effects of our general rate cases.
- Retail sales volumes increased primarily due to customer growth, including a new large industrial customer that we began serving on August 1, 2024.
- A $23.8 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $33.5 million), partially offset by an increase in sales volumes (increased revenues $9.7 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
- Electric decoupling revenue was consistent with the third quarter of 2023, with decreased current year rebate deferrals (due to lower use per customer), offset by decreased amortization of prior year rebate balances.
- A $3.3 million increase in other electric revenues primarily resulting from increased REC and transmission revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended September 30, 2024 and 2023 (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 $6.0 million and $12.5 million for the three months ended September 30, 2024 and 2023, 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 three months ended September 30 (dollars in thousands):

|  | Natural Gas Decoupling Revenues 2024 | 2023 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $2,378 | $2,390 |
| Amortization of prior year decoupling deferrals (b) | (232) | (620) |
| Total natural gas decoupling revenue | $2,146 | $1,770 |

(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 decreased $0.8 million for the third quarter of 2024 as compared to the third quarter of 2023. The primary changes that occurred during the period were as follows:

- A $2.0 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $2.9 million), partially offset by decreased sales volumes (decreased revenues $0.9 million). The decrease in sales volumes was primarily due to a 7 percent decrease in residential usage, resulting from warmer weather. Retail rates increased mainly due to the effects of our general rate cases and rate increases associated with the CCA.
- A $6.1 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $8.5 million), partially offset by an increase in sales volumes (increased revenues $2.4 million). The increase in volumes is related to increased optimization opportunities.
- A $0.4 million increase in natural gas decoupling revenues primarily due decreased amortization of prior year surcharge balances.
- A $2.3 million increase in other gas revenues primarily due to amortizations of previously deferred CCA revenues, which began April 1, 2024.

### Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the three months ended September 30, 2024 and 2023 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $6.0 million and $12.5 million for the three months ended September 30, 2024 and 2023, respectively.

Total electric resource costs decreased $9.4 million for the third quarter of 2024 as compared to the third quarter of 2023. The primary changes that occurred during the period were as follows:

- A $5.2 million decrease in power purchased due to a decrease in wholesale prices (decreased costs $14.5 million), partially offset by an increase in the volume of power purchases (increased costs $9.3 million).
- A $7.6 million decrease in fuel for generation. This was due to a decrease in fuel prices, as well as a decrease in thermal generation compared to the third quarter of 2023.
- A $3.0 million decrease in other fuel costs. These costs represent fuel and the related derivative instruments purchased for generation which were later sold when conditions indicated it was more economical to sell the fuel as part of the resource optimization process. When the fuel is sold either physically or through a derivative instrument, that revenue is included in sales of fuel.
- A $6.4 million increase in other electric resource costs, primarily related to an increase in amortization of previously deferred costs, as well as an increase in the deferral of funds related to our customer assistance payment programs (low income rate assistance and demand side management).

The following graph presents Avista Utilities' natural gas resource costs for the three months ended September 30, 2024 and 2023 (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $0.5 million and $1.2 million for the three months ended September 30, 2024 and 2023, respectively.

Total natural gas resource costs decreased $4.1 million for the third quarter of 2024 as compared to the third quarter of 2023 primarily due to the following:

- A $6.2 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $9.7 million), partially offset by an increase in volumes (increased costs $3.5 million).
- A $2.1 million increase in other primarily related to an increase in deferred PGA rebates during the period, as well as an increase in amortization of previously deferred costs. The increase in PGA rebates was due to a decrease in the price of natural gas.

### 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 three months ended September 30, 2024 and 2023 (dollars in thousands):

|  | Electric 2024 | 2023 | Natural Gas 2024 | 2023 | Intracompany 2024 | 2023 | Total 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $316,692 | $309,027 | $73,522 | $74,323 | $(6,468) | $(13,677) | $383,746 | $369,673 |
| Resource costs | 107,411 | 116,729 | 39,726 | 43,741 | (6,468) | (13,677) | 140,669 | 146,793 |
| Utility margin | $209,281 | $192,298 | $33,796 | $30,582 | $— | $— | $243,077 | $222,880 |

Electric utility margin increased $17.0 million primarily due to the effects of our general rate cases and customer growth. Natural gas utility margin increased $3.2 million primarily due to the effects of our general rate cases.

In the third quarter of 2024, we had a $3.2 million pre-tax expense under the ERM in Washington, compared to a $1.2 million pre-tax expense for the third quarter of 2023.

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.

### Nine months ended September 30, 2024 compared to the nine months ended September 30, 2023

### Utility Operating Revenues

#### Customers

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

|  | Electric Customers 2024 | 2023 | Natural Gas Customers 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 370,220 | 365,377 | 342,805 | 339,996 |
| Commercial | 45,803 | 45,200 | 37,348 | 37,033 |
| Interruptible | — | — | 51 | 50 |
| Industrial | 1,177 | 1,185 | 184 | 186 |
| Public street and highway lighting | 735 | 692 | — | — |
| Total retail customers | 417,935 | 412,454 | 380,388 | 377,265 |

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

(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 $3.5 million and $4.4 million for the nine months ended September 30, 2024 and 2023, 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 nine months ended September 30 (dollars in thousands):

|  | Electric Decoupling Revenues 2024 | 2023 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $302 | $(4,358) |
| Amortization of prior year decoupling deferrals (b) | 17,357 | 8,599 |
| Total electric decoupling revenue | $17,659 | $4,241 |

(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 $123.6 million for the first three quarters of 2024 as compared to the first three quarters of 2023. The primary changes that occurred during the period were as follows:

- A $76.1 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $71.8 million), and an increase in MWhs sold (increased revenues by $4.3 million).
- 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.
- Retail sales volumes increased primarily due to customer growth, including a large industrial customer that we began serving August 1, 2024.
- An $11.1 million decrease in wholesale electric revenues due to a decrease in sales prices (decreased revenues $34.6 million), partially offset by an increase in sales volumes (increased revenues $23.5 million). The change in volumes was due to increased opportunities to optimize our generation assets based on market conditions.
- A $35.8 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 in early 2023.
- A $13.4 million increase in electric decoupling revenue, resulting from amortization of larger prior year rebate balances. In addition, current year deferrals were in a surcharge position, as compared to a rebate position through the first three quarters of 2023, resulting from lower usage from residential customers compared to the prior year.
- A $9.9 million increase in other electric revenues, primarily resulting from increased transmission and REC revenues.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 2024 and 2023 (dollars in millions and therms in thousands):

(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 $11.4 million and $24.9 million for the nine months ended September 30, 2024 and 2023, 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 nine months ended September 30 (dollars in thousands):

|  | Natural Gas Decoupling Revenues 2024 | 2023 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $6,823 | $(8,111) |
| Amortization of prior year decoupling deferrals (b) | (1,451) | (6,077) |
| Total natural gas decoupling revenue | $5,372 | $(14,188) |

(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 increased $33.2 million for the first three quarters of 2024 as compared to the first three quarters of 2023. The primary changes that occurred during the period were as follows:

- A $2.5 million decrease in natural gas retail revenues (including industrial, which is included in other) due to decreased sales volumes (decreased revenues $11.5 million), partially offset by higher retail rates (increased revenues $9.0 million)
- Retail natural gas sales volumes decreased primarily due to decreased use by all our customer classes, partially offset by customer growth. Compared to the first three quarters of 2023, residential use per customer decreased 6 percent, commercial use per customer decreased 1 percent due to warmer weather and decreased heating loads. Industrial use per customer decreased 12 percent.
- Retail rates increased mainly due to the effects of our general rate cases and rate increases associated with the CCA.
- An $8.8 million increase in wholesale natural gas revenues due to an increase in prices (increased revenues $7.9 million), and an increase in sales volumes (increased revenues $0.9 million). The increase in prices includes the impact of

financial losses in 2023 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.

- A $19.6 million increase in natural gas decoupling revenue primarily due to surcharge deferrals in the current year resulting from lower customer usage, compared to rebate deferrals in the prior year. There were also lower amortizations in the current year of prior year surcharges compared to the first three quarters of 2023.

### Utility Resource Costs

The following graph presents Avista Utilities' electric resource costs for the nine months ended September 30, 2024 and 2023 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $11.4 million and $24.9 million for the nine months ended September 30, 2024 and 2023, respectively.

Total electric resource costs increased $63.0 million for the first three quarters of 2024 as compared to the first three quarters of 2023. The primary changes that occurred during the period were as follows:

- A $26.6 million increase in purchased power costs due to an increase in wholesale prices (increased costs $17.3 million), and an increase in the volume of power purchases (increased costs $9.3 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.
- A $6.6 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).
- A $32.8 million increase in other electric resource costs related to an increase in amortization of previously deferred costs, and an increase in deferred benefits related to current year power supply costs. There was also an increase in the deferral of funds related to our customer assistance payment programs (low income rate assistance and demand side management).

The following graph presents Avista Utilities' natural gas resource costs for the nine months ended September 30, 2024 and 2023 (dollars in millions):

Total natural gas resource costs in the graph above include intracompany resource costs of $3.5 million and $4.4 million for the nine months ended September 30, 2024 and 2023, respectively.

Total natural gas resource costs increased $19.9 million for the first three quarters of 2024 as compared to the first three quarters of 2023 primarily due to the following:

- A $68.1 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $66.7 million), and a decrease in volumes (decreased costs $1.4 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).
- An $88.0 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.

### 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 nine months ended September 30, 2024 and 2023 (dollars in thousands):

|  | Electric 2024 | 2023 | Natural Gas 2024 | 2023 | Intracompany 2024 | 2023 | Total 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $973,059 | $849,454 | $411,379 | $378,242 | $(14,942) | $(29,277) | $1,369,496 | $1,198,419 |
| Resource costs | 364,798 | 301,764 | 226,446 | 206,460 | (14,942) | (29,277) | 576,302 | 478,947 |
| Utility margin | $608,261 | $547,690 | $184,933 | $171,782 | $— | $— | $793,194 | $719,472 |

Electric utility margin increased $60.6 million primarily due to the effects of general rate cases and customer growth. Natural gas utility margin increased $13.2 million, primarily due to the effects of general rate cases.

In the first three quarters of 2024 and 2023, we had a $7.8 million pre-tax expense under the ERM in Washington.

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 was less than $0.1 million for the three months ended September 30, 2024 and $0.3 million for the three months ended September 30, 2023. For the first three quarters of 2024, net income was $5.1 million, compared to $5.7 million in 2023. The decrease in net income resulted from increased operating expenses.

### Results of Operations - Other Businesses

Our other businesses had a net loss of $1.4 million for the three months ended September 30, 2024 compared to net income of $0.9 million for the three months ended September 30, 2023. Net losses were $3.5 million for the first three quarters of 2024, compared to a net loss of $2.6 million in 2023.

The fluctuation in results is primarily related to higher net investment losses due to changes in fair value and recognizing our portion of equity investment losses.

### 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 2023 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 nine months ended September 30, 2024. See the 2023 Form 10-K for further discussion.

As of September 30, 2024, we had $212.3 million of available liquidity under the Avista Corp. committed line of credit, $43.0 million of available liquidity under our letter of credit facility, and $20.7 million under the AEL&P committed line of credit. 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.

In April 2024, we closed on the remarketing of $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds due in 2032 and 2034, respectively. The proceeds from the remarketing of these bonds were used to repay borrowings under our committed line of credit.

### Review of Condensed Consolidated Cash Flow Statement

### Operating Activities

Net cash provided by operating activities was $444.2 million for the nine months ended September 30, 2024, compared to $393.3 million for the nine months ended September 30, 2023. Contributing to the increase are power and natural gas deferrals being amortized and recovered from customers in the nine months ended September 30, 2024, compared to large deferrals in the nine months ended September 30, 2023. The net impact of these deferrals on operating cash flows was a $111.5 million increase in 2024 compared to 2023. The change in accounts payable balances during the period also contributed $63.5 million to the increased operating cash flows, as there were large balances paid during the first half of 2023 associated with elevated commodity prices at the end of 2022. These increases were partially offset by a $126.6 million decrease in collateral returned related to our derivative instruments and a $52.2 million decrease related to the change in accounts receivable, both of which were also impacted by elevated commodity prices at the end of 2022.

### Investing Activities

Net cash used in investing activities was $410.0 million for the nine months ended September 30, 2024, compared to $368.6 million for the nine months ended September 30, 2023. We paid $405.4 million for utility capital expenditures in 2024, compared to $359.3 million in 2023.

### Financing Activities

Net cash used in financing activities was $60.1 million for the nine months ended September 30, 2024, compared to net cash used of $29.5 million for the nine months ended September 30, 2023. In the first three quarters of 2024, we issued $83.7 million of long-term debt, compared to $250.0 million in the first three quarters of 2023. We also decreased our short-term borrowings by $61.8 million in the nine months ended September 30, 2024, compared to $241.5 million in the nine months ended September 30, 2023. In addition, we issued $35.7 million of common stock and paid $112.5 million in dividends in the nine months ended September 30, 2024, compared to issuing common stock of $88.2 million and paying $105.2 million in dividends in 2023.

### Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):

|  | September 30, 2024 Amount | Percent of total | December 31, 2023 Amount | Percent of total |
| --- | ---: | ---: | ---: | ---: |
| Current portion of long-term debt and leases | $23,037 | 0.4% | $22,890 | 0.4% |
| Short-term borrowings | 287,250 | 5.2% | 349,000 | 6.3% |
| Long-term debt to affiliated trusts | 51,547 | 0.9% | 51,547 | 0.9% |
| Long-term debt and leases | 2,700,453 | 48.3% | 2,618,012 | 47.4% |
| Total debt | 3,062,287 | 54.8% | 3,041,449 | 55.0% |
| Total shareholders’ equity | 2,528,088 | 45.2% | 2,485,323 | 45.0% |
| Total | $5,590,375 | 100.0% | $5,526,772 | 100.0% |

Our shareholders’ equity increased $42.8 million during the first three quarters of 2024 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 and an expiration date of June 2028, with the option to extend 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.

In December 2022, we entered into a revolving credit agreement in the amount of $100 million, which was terminated in June 2023.

The following table summarizes the balances outstanding and available liquidity as of September 30, 2024 (dollars in thousands):

|  | Amount of Facility | Borrowings Outstanding | Letters of Credit Outstanding (1) | Available Liquidity |
| --- | ---: | ---: | ---: | ---: |
| Line of Credit expiring June 2028 | $500,000 | $283,000 | $4,700 | $212,300 |
| Letter of Credit Facility | 50,000 | N/A | 7,000 | 43,000 |
| Total | $550,000 | $283,000 | $11,700 | $255,300 |

62

(1) 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 September 30, 2024, we complied with this covenant with a ratio of 54.8 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 nine months ended September 30 (dollars in thousands):

| $500 million line of credit, expiring June 2028 | 2024 | 2023 |
| --- | ---: | ---: |
| Maximum balance outstanding during the period | $349,000 | $334,500 |
| Average balance outstanding during the period | 256,226 | 239,073 |
| Average interest rate during the period | 6.44% | 5.91% |
| Average interest rate at end of the period | 6.13% | 6.24% |
| **$100 million line of credit, terminated June 2023** |  |  |
| Maximum balance outstanding during the period (1) | N/A | 15,000 |
| Average balance outstanding during the period (1) | N/A | 283 |
| Average interest rate during the period (1) | N/A | 7.75% |

(1) Amounts for the period are through the termination date of June 8, 2023.

#### AEL&P

AEL&P has a $25.0 million committed line of credit that expires in June 2028. As of September 30, 2024, there was $4.3 million outstanding under this committed line of credit, and $20.7 million of available liquidity.

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 September 30, 2024, AEL&P complied with this covenant with a ratio of 47.8 percent.

As of September 30, 2024, 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 April 2024, we remarketed revenue bonds previously held by us, resulting in an additional $83.7 million of long-term debt. We do not expect to issue any additional long-term debt in 2024. We expect to issue $70 million of common stock in 2024 (including $35.7 million issued through September 30, 2024).

### 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 $515 million in 2024. We expect Avista Utilities' capital expenditures to be $525 million in 2025, $575 million in 2026, and $600 million in 2027. See the 2023 Form 10-K for further information on our expected capital expenditures.

### Pension Plan

### Avista Utilities

In the nine months ended September 30, 2024, we contributed $10.0 million to the pension plan, and do not expect further contributions in 2024. We expect to contribute a total of $40.0 million to the pension plan in the period 2025 through 2028, with an annual contribution of $10.0 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 nine months ended September 30, 2024 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.

Both the commercial and residential building and energy codes were the subject of legal challenges in both Washington State Superior Court (the State Action) and in the Federal District Court for the Eastern District of Washington (the Federal Action). In the Federal Action, to which the Company was a party, the plaintiffs challenged the amendments on the grounds that they were preempted by the federal Energy Policy and Conservation Act (EPCA), citing the Ninth Circuit’s decision in California Restaurant Association v. Berkeley (the Berkeley Decision), which involved similar restrictions on the use of natural gas in new construction in Berkeley, California.

In May 2023, the SBCC voted to delay the effective date of the code amendments and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley Decision. As a result of this action, in July 2023, the Federal District Court declined to issue a preliminary injunction to prevent the amendments from taking effect. The plaintiffs in the Federal Action subsequently dismissed the action, without prejudice to their ability to refile after the SBCC rulemaking process is complete.

The SBCC has since voted to approve revised residential and commercial energy regulations that continue to require new residential and commercial buildings in Washington to use electricity as the primary heat source. In light of this action, the plaintiffs in the State Action amended their complaint to challenge the new regulations. The State Action remains pending.

In May 2024, we, along with Cascade Natural Gas Corporation, Northwest Natural Gas Company, and a coalition of homebuilders, heating unit dealers and other parties, filed a lawsuit challenging the approved building codes on the grounds that they are preempted by EPCA. The lawsuit was filed in the United States District Court for the Western District of Washington. This lawsuit 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.

### Washington Climate Commitment Act

The CCA, and its implementing regulations, established a cap and trade program to reduce GHG emissions and achieve the GHG limits previously established under state law. The final rules implement a cap on emissions, provide mechanisms for the sale and tracking of tradable emissions allowances and establish additional compliance and accountability measures. The state issues allowances necessary to serve our Washington retail electric load; off-system wholesale sales may result in additional obligation costs. The CCA also has direct impacts on our Idaho electric operations as it applies to power that is delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is delivered to Idaho customers. Annually, the model and its resulting calculations must be certified by an independent third party and submitted to the Washington Department of Ecology (Ecology) for approval. If the independent third party or Ecology disagrees with the approach or any of the calculations, it could result in a change to the number of allowances needed for compliance and could result in changes to anticipated costs for our electric operations. For Washington electric, we are allowed to defer any incremental costs associated with the CCA in accordance with our regulatory accounting order; however, in Idaho we are not allowed to pass any costs associated with CCA compliance to Idaho customers. See "Note 15 of the Notes to Condensed Consolidated Financial Statements" for further discussion of the CCA costs associated with our electric operations and impacts on our financial results.

For our Washington natural gas operations, we expect additional financial burdens associated with compliance which will be deferred in accordance with our regulatory accounting order in Washington (see "Executive Overview" for discussion of the CCA).

### SEC Climate Disclosure Rules

In March 2024, the SEC adopted final rules requiring certain climate disclosures to be incorporated into SEC filings. The final rules as written are effective for our filings starting with the 2025 Annual Report on Form 10-K.

After the final rules were published by the SEC, multiple lawsuits were made, including allegations that the SEC does not have statutory rulemaking authority over climate reporting, among other various allegations. The SEC requested the cases be consolidated into one action, and the consolidated action is now before the United States Circuit Court of Appeals for the Eighth Circuit.

In April 2024, the SEC voluntarily stayed the implementation of the final rules. In the stay order, the SEC noted it intends to vigorously defend the validity of the final rules.

### EPA Regulations for Power Plants

On April 25, 2024, the EPA released a package of final regulations addressed to electric generation facilities. These include:

- *Greenhouse gas regulations for new natural gas-based turbines and existing coal-based units, pursuant to section 111 of the Clean Air Act*. This rule finalizes (a) the repeal of the Affordable Clean Energy rule; (b) guidelines for GHG emissions from existing fossil fuel-fired steam generating electric generating units; and (c) revisions to existing performance standards for new, reconstructed or heavily modified fossil fuel-fired stationary combustion turbine electric generating units.
- *Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (ELG Rule)*. The ELG Rule applies to wastewater discharges from coal-based generating units and establishes pollution control requirements. The Rule builds upon the 2015 and 2020 ELG Rules. It includes a subcategory of requirements for coal plants that will be retired or repowered by the end of 2028 and provides additional compliance pathways for coal plants that retire by the end of 2034.
- *Updated Mercury and Air Tox Standards, pursuant to section 112 of the Clean Air Act (MATS Rule)*. The MATS Rule sets emissions limits for filterable particulate matter for coal-based generating units. The Rule reduces those limits from the standards that were originally set in 2012.
- *Disposal of Coal Combustion Residuals from Electric Utilities – Legacy CCR Surface Impoundments (CCR Rule)*. The CCR Rule builds on 2015 regulations, which apply to active power plants that dispose of coal combustion residuals in

surface impoundments or landfills, by regulating inactive surface impoundments at inactive power plants and CCR management units at active and inactive power plants.

We continue to analyze each of these rules to assess the impact, if any, it may have on our existing generating units, including Colstrip and/or our natural gas-fired generating units. A substantial number of legal challenges have been filed regarding these rules. At this time, we do not believe the implementation of these rules will impact our agreement to transfer our Colstrip ownership to NorthWestern, which is planned to close on December 31, 2025.

In anticipation of a 2027 compliance date, Talen, as operator of Colstrip, has proposed that the owners begin design and engineering work on emission control technology that would ensure compliance with the rule. That work is anticipated to begin in 2024 and continue through completion of the project in 2027. We are currently in discussions with NorthWestern regarding how our potential share of the costs for this work should be allocated.

Along with the other owners (including the operator), we have assessed the CCR Rule and believe there will not be a material change to our asset retirement obligation for Colstrip.

See the 2023 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 2023 Form 10-K and have not materially changed during the nine months ended September 30, 2024. See the 2023 Form 10-K.

### Financial Risk

Our financial risks have not materially changed during the nine months ended September 30, 2024. Refer to the 2023 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2023.

#### 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 September 30, 2024 and December 31, 2023 and the amount of additional collateral we would have to post in certain circumstances.

#### Credit Risk

Under the terms of interest rate swap derivatives, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. A downgrade in our credit ratings could further impact the amount of collateral required. See “Credit Ratings” in the 2023 Form 10-K for further information. As of September 30, 2024, we had interest rate swap derivatives outstanding with a notional amount totaling $10.0 million and we had no cash deposited as collateral and no letters of credit outstanding for these interest rate swap derivatives. If our credit ratings were lowered to below “investment grade” based on our interest rate swap derivatives outstanding at September 30, 2024, the amounts we would be required to post for additional collateral are immaterial.

As of September 30, 2024, we had cash deposited as collateral of $24.8 million and letters of credit of $7.0 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 2023 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 September 30, 2024 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

|  | September 30, 2024 |
| --- | ---: |
| Additional collateral taking into account contractual thresholds | $26,140 |
| Additional collateral without contractual thresholds | 48,500 |

### Energy Commodity Risk

Our energy commodity risks have not materially changed during the nine months ended September 30, 2024. See the 2023 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of September 30, 2024 expected to be delivered in each respective year (dollars in thousands). There are 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) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Remainder 2024 | $298 | $— | $(8,239) | $(10,110) | $2,626 | $3,746 | $(2,383) | $(1,336) |
| 2025 | — | — | (15,980) | (11,923) | 5,065 | 3,062 | (4,630) | (1,084) |
| 2026 | — | — | (6,273) | (2,311) | — | — | — | — |
| 2027 | — | — | (1,121) | (148) | — | — | — | — |

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2023 expected to be delivered in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2026.

| 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) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2024 | $746 | $— | $(7,485) | $(50,899) | $6,990 | $1,502 | $(3,495) | $1,222 |
| 2025 | — | — | (5,781) | (5,166) | — | 295 | (4,349) | (1,348) |
| 2026 | — | — | (940) | (431) | — | — | — | — |

(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.

## 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, 1,935 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 September 30, 2024.

There have been no changes in the Company's internal control over financial reporting that occurred during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

## Risk factors

As filed, 441 characters.

Refer to the 2023 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 2023 Form 10-K.

Filed Nov 6, 2024.
Source: SEC EDGAR, the filing index for accession 0000950170-24-121737. Last ingested by Listed: Oct 24, 2026, 14:55 ET. No prices; not investment advice.