# Avista Corp: Form 10-Q for the period ended Sep 30, 2023

- Company: [Avista Corp](/companies/ava.md) (CIK 104918)
- Form: 10-Q
- Filed: 2023-11-01
- Accepted by EDGAR: Oct 31, 2023, 22:44 ET
- Period: 2023-09-30
- Accession: 0000950170-23-057042
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/104918/000095017023057042/ava-20230930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/104918/000095017023057042/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-07-01 to 2023-09-30 | $379.6m | us-gaap:Revenues |
| Revenue | 9 months, 2023-01-01 to 2023-09-30 | $1.23bn | us-gaap:Revenues |
| Operating income | 3 months, 2023-07-01 to 2023-09-30 | $38.1m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2023-01-01 to 2023-09-30 | $158.5m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2023-07-01 to 2023-09-30 | −$3.8m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2023-01-01 to 2023-09-30 | −$16.2m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-07-01 to 2023-09-30 | $14.7m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2023-01-01 to 2023-09-30 | $87.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-07-01 to 2023-09-30 | $0.19 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2023-01-01 to 2023-09-30 | $1.14 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-07-01 to 2023-09-30 | $0.19 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2023-01-01 to 2023-09-30 | $1.15 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-07-01 to 2023-09-30 | 76,761,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2023-01-01 to 2023-09-30 | 76,056,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2023-01-01 to 2023-09-30 | $393.3m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2023-01-01 to 2023-09-30 | $359.3m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 9 months, 2023-01-01 to 2023-09-30 | $105.2m | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2023-09-30 | $8.6m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-09-30 | $547.2m | us-gaap:AssetsCurrent |
| Total assets | at 2023-09-30 | $7.47bn | us-gaap:Assets |
| Current liabilities | at 2023-09-30 | $583.5m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-09-30 | $5.06bn | us-gaap:Liabilities |
| Short-term borrowings | at 2023-09-30 | $221.5m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2023-09-30 | $2.41bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 69,885 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 2022 Form 10-K.

### Business Segments

Our business segments have not changed during the nine months ended September 30, 2023. See the 2022 Form 10-K as well as “Note 17 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, 2023 | 2022 | Nine months ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Avista Utilities | $13,498 | $(5,987) | $83,935 | $65,241 |
| AEL&P | 288 | 228 | 5,689 | 4,292 |
| Other | 930 | (39) | (2,579) | 7,687 |
| Net income (loss) | $14,716 | $(5,798) | $87,045 | $77,220 |

### Executive Overview

### Overall Results

Net income for the three months ended September 30, 2023 increased compared to the three months ended September 30, 2022, primarily due to increased utility revenues and increased income tax benefits. Utility revenues increased due to increased electric wholesale and decoupling revenues, as well as increased natural gas and electric retail rates. These increases were partially offset by an increase in interest expense, resulting from increased borrowings outstanding during the period as well as increased interest rates compared to the third quarter of 2022, as well as an increase in depreciation and amortization expense.

Net income for the nine months ended September 30, 2023 increased compared to the nine months ended September 30, 2022 primarily due to an increase in utility revenues, resulting from customer growth and the effects of general rate cases, and decreased resource costs. This was partially offset by increased interest expense resulting from increased borrowings outstanding during the period and increased interest rates, increased operating costs, and increased depreciation and amortization expense. Our other businesses also recognized net investment losses in 2023, compared to net investment gains in 2022.

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.

### 2023 Hydroelectric Generation

In May and June of 2023, our region experienced historically high temperatures, causing the snowpack to melt more rapidly than expected. The quick runoff had a significant negative impact on our hydrogeneration resources, resulting in one of our worst years for hydroelectric generation. As a result, we increased thermal generation and purchased power to compensate for the decrease in available hydroelectric generation, and our ability to optimize our generation assets was limited compared to the opportunities we originally expected for the year. The decreased availability of hydroelectric generation compared to our expectations had a significant impact on the ERM in Washington, as well as our financial results.

### 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. See "Environmental Issues and Contingencies" for further discussion of the CCA and expected impacts to our financial results.

### Inflation

Although we continue to experience inflationary pressures in multiple areas of our business, inflation has eased considerably compared to the same period last year. Nevertheless, inflation remains above the Federal Reserve's target and we cannot estimate how long inflation will remain at elevated levels. In addition, our interest costs increased due to higher interest rates than those approved in our most recent general rate cases, resulting in increased interest expense.

### 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 operating expenses and interest costs will have to be addressed in future rate cases. See “Regulatory Matters” for additional discussion of the general rate cases.

### Climate Change

There is a trend of increasing average temperatures that has had, and will likely continue to have, various direct and indirect impacts on our business. Direct impacts include, without limitation, variations in the amount and timing of energy demand throughout the year, variations in the level and timing of precipitation throughout the year and the resulting impact on the availability of hydroelectric resources at times of peak demand as well as an increased risk of wildfire. Indirect impacts include, without limitation, federal, state and local legislation or regulation (in effect and proposed) that limits (or eliminates) the use of fossil-fuel for electric generation, as well as the use of natural gas for heating in residential and commercial buildings.

For additional information regarding climate change, effects of climate change on our operations and results of operations and legislation and regulation designed to mitigate climate change, see "Environmental Issuance and Contingencies" and our 2022 Form 10-K.

### 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 regards 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

#### 2022 General Rate Cases

In December 2022, the WUTC issued an order approving the multi-party settlement agreement filed in June 2022. The approved rates were designed to increase annual base electric revenues by $38.0 million (or 6.9 percent), effective in December 2022, and $12.5 million (or 2.1 percent), effective in December 2023. The approved rates were also designed to increase annual base natural gas revenues by $7.5 million (or 6.5 percent), effective in December 2022, and $1.5 million (or 1.2 percent), effective in December 2023.

To mitigate the overall impact of the revenue increases on customers, we offset part of the 2022 base rate request with tax customer credits. The total estimated benefits of these credits, $27.6 million for electric customers and $12.5 million for natural gas customers, will be returned over a two-year period from December 2022 to December 2024.

In addition, the order approved a separate tracking mechanism and tariff for purposes of recovering existing and prospective Colstrip costs.

The WUTC approved an ROR on rate base of 7.03 percent, but the settlement does not specify an explicit ROE, cost of debt or capital structure.

These general rate cases require a subsequent review of additions to utility plant included in rates and a refund of revenues if capital expenditures are not at the level contemplated in the rate case.

#### 2024 General Rate Cases

The Company expects to file its next Washington electric and natural gas general rate cases in the first quarter of 2024.

### 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 $22.1 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 IPUC approved an ROE of 9.4 percent, based on a common equity ratio of 50 percent, and an ROR on rate base of 7.19 percent.

### Oregon General Rate Case

#### 2023 General Rate Case

In October 2023, the OPUC approved the all party settlement agreement filed in August 2023. The approved rates are designed to increase annual base natural gas revenues by $7.2 million (or 9.4 percent). The OPUC approved an ROR on rate base of 7.24 percent, a common equity ratio of 50 percent, and an ROE of 9.5 percent. New rates will be effective on January 1, 2024.

### 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 is effective in October 2023.

### Avista Utilities

### Purchased Gas Adjustments

PGAs are designed to pass through changes in natural gas costs to customers with no change in utility margin (operating revenues less resource costs) or net income. 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 that is not hedged. Total net deferred natural gas costs among all jurisdictions were assets of $78.3 million and $52.1 million as of September 30, 2023 and December 31, 2022, respectively.

### Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used 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 Washington customers. See the 2022 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 $36.1 million and $30.5 million as of September 30, 2023 and December 31, 2022, respectively. These deferred power cost balances represent amounts due from customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, we must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. In June 2023, we received approval from the WUTC for a rate surcharge to customers over a two-year period, effective July 1, 2023.

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 between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were assets of $12.4 million and $16.3 million as of September 30, 2023 and December 31, 2022, respectively. These deferred power cost balances represent amounts due from customers.

### 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 are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in our decoupling mechanisms. See the 2022 Form 10-K for a discussion of the mechanisms in each jurisdiction.

Total net cumulative decoupling deferrals among all jurisdictions were regulatory liabilities of $29.5 million as of September 30, 2023 and $18.2 million as of December 31, 2022. 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 2023 and 2022 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, 2023 compared to the three months ended September 30, 2022

The following graph shows the total change in net income for the third quarter of 2023 compared to the third quarter of 2022, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased primarily due to increased electric wholesale and decoupling revenues, as well as increased natural gas and electric retail revenues. Retail revenues increased primarily due to increased rates and natural gas usage. These increases were offset by decreased sales of fuel.

Utility resource costs slightly increased due to increased purchased power costs, partially offset by decreased natural gas prices and fuel costs.

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

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher energy commodity prices and additional requirements for cash collateral. See the "Executive Overview" for further discussion of inflation.

Income tax was a benefit in the third quarter of 2023, compared to an expense in the third quarter of 2022. The change is primarily due to increased tax customer credits offsetting the bill impact of rate increases included in our 2022 Washington GRCs, partially offset by the timing impact of spreading the increased credits over the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to increased interest income, decreased property tax expense, and increased net investment gains in 2023.

### Nine months ended September 30, 2023 compared to the nine months ended September 30, 2022

The following graph shows the total change in net income for the third quarter of 2023 compared to the third quarter of 2022, as well as the various factors that caused such change (dollars in millions):

Utility revenues increased primarily due to increased natural gas retail revenues associated with increased retail rates (primarily PGAs), particularly during the first quarter of 2023, as well as increased electric wholesale activities. This was partially offset by decreased natural gas wholesale revenues and financial losses on our derivative contracts, which are netted with utility revenues.

Utility resource costs decreased primarily due to financial gains related to our hedging activities that are netted with our expenses. These decreases were partially offset by increases in purchased power prices during the period, as well as increased natural gas prices during the first quarter.

Utility operating expenses increased when compared to the first three quarters of 2022, primarily due to inflationary pressures resulting in increased labor costs, as well as increased net amortizations of previously deferred costs. This was partially offset by a decrease in pension expense and a decrease due to the $4.0 million write off of Dry Ash Disposal System assets in the second quarter of 2022. See the "Executive Overview" for further discussion of inflation.

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

Interest expense increased due to higher interest rates associated with inflation, as well as increased borrowings outstanding during the period. Borrowings increased due to capital expenditures, higher energy commodity prices and additional requirements for cash collateral. See the "Executive Overview" for further discussion of inflation.

Income tax benefit increased primarily due the tax customer credits offsetting the bill impact of rate increases included in our 2021 Washington and Idaho GRCs, and the 2022 Washington GRCs. Income tax is spread throughout the year as a percentage of pre-tax income based on the estimated annual effective tax rate. See "Note 8 of the Notes to Condensed Consolidated Financial Statements" for further details and a reconciliation of our effective tax rate.

The increase in other was primarily related to increased interest income, decreased property tax expense, and decreased other non-utility operating expenses. This was partially offset by investment losses recognized in 2023, compared to investment gains in 2022

### 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. In the AEL&P section, we include a discussion of utility margin, which is also a non-GAAP financial measure.

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 17 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

### Three months ended September 30, 2023 compared to the three months ended September 30, 2022

### Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the three months ended September 30, 2023 and 2022 (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 $1.2 million and $3.7 million for the three months ended September 30, 2023 and 2022, respectively.

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

|  | Electric Decoupling Revenues 2023 | 2022 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $(2,312) | $(6,548) |
| Amortization of prior year decoupling deferrals (b) | 4,121 | (3,431) |
| Total electric decoupling revenue | $1,809 | $(9,979) |

(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 $8.0 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

- a $1.5 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $6.4 million) partially offset by a decrease in MWhs sold (decreased revenues by $4.9 million).
- Retail rates increased mainly due to the effects of our general rate cases and the ERM surcharge to customers in 2023.
- Retail sales volumes decreased primarily due to decreased use by our residential and commercial customers. Compared to the third quarter of 2022, residential and commercial use per customer decreased 3 percent. Cooling degree days in Spokane were 15 percent below the prior year, but were 23 percent above our historical norm. These decreases were partially offset by customer growth.
- a $20.5 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $12.7 million) and an increase in sales volumes (increased revenues $7.8 million). The fluctuation of volumes was due to increased thermal generation, which allowed for additional opportunities to optimize our generation assets.
- a $24.4 million decrease in sales of fuel as part of increased thermal generation and decreased fuel resource optimization activities, including associated financial hedging activities.
- an $11.8 million increase in electric decoupling revenue, resulting mostly from amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022. Current year deferrals were lower due to decreased use per customer.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the three months ended September 30, 2023 and 2022 (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 $12.5 million and $18.2 million for the three months ended September 30, 2023 and 2022, respectively.

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

|  | Natural Gas Decoupling Revenues 2023 | 2022 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $2,390 | $4,201 |
| Amortization of prior year decoupling deferrals (b) | (620) | (71) |
| Total natural gas decoupling revenue | $1,770 | $4,130 |

(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 increased $3.8 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

- an $11.4 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $6.3 million) and higher sales volumes (increased revenues $5.1 million).
- Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin), and the effects of our general rate cases.
- Retail natural gas sales volumes increased primarily due to increased residential and commercial usage, resulting from cooler weather. Compared to the third quarter of 2022, residential use per customer increased 9 percent, and commercial firm use per customer increased 6 percent. Customer growth also contributed to the increase.
- a $5.1 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $10.2 million), partially offset by an increase in sales volumes (increased revenues $5.1 million). Differences between revenues and

costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.

- a $2.3 million decrease in natural gas decoupling revenue primarily due to decreased surcharges to residential customers (due to higher use per customer) and increased amortization of prior year surcharge balances.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the three months ended September 30, 2023 and 2022:

|  | Electric Customers 2023 | 2022 | Natural Gas Customers 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 366,053 | 361,875 | 339,843 | 336,916 |
| Commercial | 45,153 | 44,546 | 36,899 | 36,700 |
| Interruptible | — | — | 51 | 44 |
| Industrial | 1,177 | 1,189 | 185 | 189 |
| Public street and highway lighting | 700 | 685 | — | — |
| Total retail customers | 413,083 | 408,295 | 376,978 | 373,849 |

### Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the three months ended September 30, 2023 and 2022 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $12.5 million and $18.2 million for the three months ended September 30, 2023 and 2022, respectively.

Total electric resource costs decreased $10.2 million for the third quarter of 2023 as compared to the third quarter of 2022. The primary changes that occurred during the period were as follows:

- a $17.5 million increase in power purchased due to an increase in wholesale prices (increased costs $20.2 million) partially offset by a decrease in the volume of power purchases (decreased costs $2.7 million).
- a $15.1 million decrease in fuel for generation due to decreased natural gas fuel prices, partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.
- a $15.1 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 $2.6 million increase in other electric resource costs, primarily related to an increase in amortization of previously deferred costs.

Total natural gas resource costs in the graph above include intracompany resource costs of $1.2 million and $3.7 million for the three months ended September 30, 2023 and 2022, respectively.

Total natural gas resource costs increased $2.4 million for the third quarter of 2023 as compared to the third quarter of 2022 primarily due to the following:

- a $2.2 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $9.4 million), partially offset by an increase in volumes (increased costs $7.2 million). The increase in volumes is primarily due to increased retail usage and increased wholesale activity.
- a $4.6 million increase from net amortizations and deferrals of natural gas costs, primarily related to an increase in amortization of previously deferred costs.

### Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the three months ended September 30, 2023 and 2022 (dollars in thousands):

|  | Electric 2023 | 2022 | Natural Gas 2023 | 2022 | Intracompany 2023 | 2022 | Total 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $309,027 | $301,003 | $74,323 | $70,553 | $(13,677) | $(21,901) | $369,673 | $349,655 |
| Resource costs | 116,729 | 126,962 | 43,741 | 41,323 | (13,677) | (21,901) | 146,793 | 146,384 |
| Utility margin | $192,298 | $174,041 | $30,582 | $29,230 | $— | $— | $222,880 | $203,271 |

Electric utility margin increased $18.3 million and natural gas utility margin increased $1.4 million.

Electric utility margin increased primarily due to the effects of general rate cases, customer growth and the impacts of the ERM.

In the third quarter of 2023, we had a $1.2 million pre-tax expense under the ERM in Washington, compared to a $4.5 million pre-tax expense for the third quarter of 2022.

Natural gas utility margin increased primarily due to customer growth and the effects of general rate cases.

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, 2023 compared to the nine months ended September 30, 2022

### Utility Operating Revenues

The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30, 2023 and 2022 (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 $4.4 million and $8.1 million for the nine months ended September 30, 2023 and 2022, respectively.

The following table presents the current year deferrals and the amortization of prior year decoupling balances reflected in utility electric operating revenues for the nine months ended September 30 (dollars in thousands):

|  | Electric Decoupling Revenues 2023 | 2022 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $(4,358) | $(14,644) |
| Amortization of prior year decoupling deferrals (b) | 8,599 | (9,316) |
| Total electric decoupling revenue | $4,241 | $(23,960) |

(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 decreased $1.1 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

- a $5.1 million increase in retail electric revenue due to an increase in retail rates (increased revenues by $8.6 million), partially offset by a decrease in MWhs sold (decreased revenues by $3.5 million).
- Retail rates increased primarily due to the effects of our general rate cases and the ERM surcharge to customers in 2023.
- Retail sales volumes decreased primarily due to decreased use by our residential and commercial customers. Compared to the first three quarters of 2022, residential and commercial use per customer decreased 2 percent. These decreases were partially offset by customer growth.
- a $68.0 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $54.9 million) and an increase in sales volumes (increased revenues $13.1 million). The fluctuation of volumes was due to resource optimization activities.
- a $104.7 million decrease in sales of fuel as part of thermal generation resource optimization activities, including associated financial hedging activities, which includes net losses on derivative instruments resulting from commodity price volatility early in the year.
- a $28.2 million increase in electric decoupling revenue, resulting from decreasing rebates in 2023 resulting from lower usage from residential customers compared to the prior year, as well as amortization of prior year rebate balances in 2023, compared to amortization of surcharge balances in 2022.

The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the nine months ended September 30, 2023 and 2022 (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 $24.9 million and $39.4 million for the nine months ended September 30, 2023 and 2022, respectively.

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

|  | Natural Gas Decoupling Revenues 2023 | 2022 |
| --- | ---: | ---: |
| Current year decoupling deferrals (a) | $(8,111) | $(3,704) |
| Amortization of prior year decoupling deferrals (b) | (6,077) | (755) |
| Total natural gas decoupling revenue | $(14,188) | $(4,459) |

(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 increased $14.3 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

- a $76.3 million increase in natural gas retail revenues (including industrial, which is included in other) due to higher retail rates (increased revenues $75.3 million) and increased sales volumes (increased revenues $1.0 million).
- Retail rates increased mainly due to PGA rate increases in all jurisdictions (which do not impact utility margin), as well as the effects of our general rate cases.
- Retail natural gas sales volumes increased primarily due to increased use by our industrial interruptible customers and customer growth. This increased usage was partially offset by decreased residential and commercial usage, due to warmer weather (decreasing heating load). Compared to the first three quarters of 2022, residential use per customer decreased 3 percent, and commercial use per customer decreased 1 percent. Heating degree days in Spokane were 9 percent below the prior year and 7 percent below our historical norm. Heating degree days in Medford were 2 percent above the prior year and 8 percent above normal.
- a $51.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $51.5 million), and a decrease in sales volumes (decreased revenues $0.4 million). The decrease in prices includes the impact of financial losses associated with our hedging activities, which nets with our wholesale revenues. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms.
- a $9.7 million decrease in natural gas decoupling revenue primarily due to higher rebates to residential customers in the first quarter of 2023 due to higher than normal usage, as well as higher amortization of surcharge balances.

The following table presents Avista Utilities' average number of electric and natural gas retail customers for the nine months ended September 30, 2023 and 2022:

|  | Electric Customers 2023 | 2022 | Natural Gas Customers 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Residential | 365,377 | 360,947 | 339,996 | 336,479 |
| Commercial | 45,200 | 44,513 | 37,033 | 36,732 |
| Interruptible | — | — | 50 | 44 |
| Industrial | 1,185 | 1,194 | 186 | 189 |
| Public street and highway lighting | 692 | 679 | — | — |
| Total retail customers | 412,454 | 407,333 | 377,265 | 373,444 |

### Utility Resource Costs

The following graphs present Avista Utilities' resource costs for the nine months ended September 30, 2023 and 2022 (dollars in millions):

Total electric resource costs in the graph above include intracompany resource costs of $24.9 million and $39.4 million for the nine months ended September 30, 2023 and 2022, respectively.

Total electric resource costs decreased $32.7 million for the first three quarters of 2023 as compared to the first three quarters of 2022. The primary changes that occurred during the period were as follows:

- a $43.9 million increase in power purchased due to an increase in wholesale prices (increased costs $38.6 million), and an increase in the volume of power purchases (increased costs $5.3 million).
- a $24.5 million decrease in fuel for generation primarily due to financial gains associated with our hedging activities, which net with our physical purchases, as well as decreased natural gas prices. This was partially offset by an increase in thermal generation volumes due in part to decreased hydroelectric generation.
- a $51.5 million decrease in other fuel costs, resulting from financial gains associated with our hedging activities. These costs represent fuel and the related derivative instruments purchased for generation but 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.

Total natural gas resource costs in the graph above include intracompany resource costs of $4.4 million and $8.1 million for the nine months ended September 30, 2023 and 2022, respectively.

Total natural gas resource costs increased $4.4 million for the first three quarters of 2023 as compared to the first three quarters of 2022 primarily due to the following:

- a $7.4 million increase in natural gas purchased due to an increase in the price of natural gas (increased costs $8.1 million), partially offset by a decrease in volumes (decreased costs $0.7 million).
- a $3.0 million decrease from net amortizations and deferrals of natural gas costs.

### Utility Margin

The following table reconciles Avista Utilities' operating revenues, as presented in "Note 17 of the Notes to Condensed Consolidated Financial Statements" to the Non-GAAP financial measure utility margin for the nine months ended September 30, 2023 and 2022 (dollars in thousands):

|  | Electric 2023 | 2022 | Natural Gas 2023 | 2022 | Intracompany 2023 | 2022 | Total 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Operating revenues | $849,454 | $850,561 | $378,242 | $363,984 | $(29,277) | $(47,503) | $1,198,419 | $1,167,042 |
| Resource costs | 301,764 | 334,481 | 206,460 | 202,051 | (29,277) | (47,503) | 478,947 | 489,029 |
| Utility margin | $547,690 | $516,080 | $171,782 | $161,933 | $— | $— | $719,472 | $678,013 |

Electric utility margin increased $31.6 million and natural gas utility margin increased $9.8 million.

Electric utility margin increased primarily due to customer growth and the effects of general rate cases.

In the first three quarters of 2023, we had a $7.8 million pre-tax expense under the ERM in Washington, compared to a $7.3 million pre-tax expense for the first three quarters of 2022.

Natural gas utility margin increased primarily due to customer growth and the effects of general rate cases.

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 $0.3 million for the three months ended September 30, 2023 and $0.2 million for the three months ended September 30, 2022. Net income was $5.7 million for the nine months ended September 30, 2023, compared to $4.3 million for the nine months ended September 30, 2022.

The following table presents AEL&P's operating revenues, resource costs and resulting utility margin for the three and nine months ended September 30, 2023 and 2022 (dollars in thousands):

|  | Three months ended September 30, 2023 | 2022 | Nine months ended September 30, 2023 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Operating revenues | $9,851 | $9,637 | $35,408 | $32,597 |
| Resource costs | 1,489 | 1,400 | 3,507 | 3,020 |
| Utility margin | $8,362 | $8,237 | $31,901 | $29,577 |

Utility margin for the three and nine months ended September 30 increased from 2022, primarily due to increased operating revenues resulting from rate increases compared to the prior year. Increased usage has also contributed to increased revenues year to date.

### Results of Operations - Other Businesses

Our other businesses had net income of $0.9 million for the three months ended September 30, 2023 compared to a net loss of less than $0.1 million for the three months ended September 30, 2022. Net loss was $2.6 million for the nine months ended September 30, 2023, compared to net income of $7.7 million for the nine months ended September 30, 2022.

The decrease in results primarily relates to decreases in the fair value of our investments in 2023, compared to net investment gains recognized in 2022. See "Note 12 of the Notes to the Condensed Consolidated Financial Statements" for further discussion of our equity investment fair value.

### 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 2022 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, 2023. See the 2022 Form 10-K for further discussion.

In March 2023, we issued $250.0 million of first mortgage bonds. A portion of the proceeds from the sale of these bonds was used for the construction or improvement of utility facilities, and a portion was used to refinance existing indebtedness, including the repayment of our $150.0 million term loan.

As of September 30, 2023, we had $275.4 million of available liquidity under the Avista Corp. committed line of credit, $41.0 million of available liquidity under our letter of credit facility, and $23.5 million under the AEL&P committed line of credit. With our existing credit facilities and the expected issuances of common stock and debt within the next year, we believe we have adequate liquidity to meet our needs for the next 12 months.

### Review of Consolidated Cash Flow Statement

### Operating Activities

Net cash provided by operating activities was $393.3 million for the nine months ended September 30, 2023, compared to $210.4 million for the nine months ended September 30, 2022. The increase is primarily due to a decrease in collateral for our derivatives resulting in a $173.5 million increase to operating cash flows in 2023 compared to 2022, a decrease in our accounts and notes receivable balance outstanding resulting in an $87.6 million increase to operating cash flows in 2023 compared to 2022, and a net $7.5 million received for interest rate swap settlements during the period compared to $17.0 million paid in 2022. We also contributed $32.0 million less to the pension plan in 2023 compared to 2022, resulting in increased operating cash flows. These increases in operating cash flows were partially offset by decreases in our accounts payable outstanding balance associated with elevated commodity prices at the end of 2022, which decreased operating cash flows by $74.6 million compared to 2022.

### Investing Activities

Net cash used in investing activities was $368.6 million for the nine months ended September 30, 2023, compared to $340.3 million for the nine months ended September 30, 2022. We paid $359.3 million for utility capital expenditures in 2023, compared to $331.3 million in 2022. Additionally, we contributed capital of $12 million to our equity and property investments, compared to $9.1 million in the first three quarters of 2022.

### Financing Activities

Net cash used in financing activities was $29.5 million for the nine months ended September 30, 2023, compared to net cash provided by financing activities of $122.1 million for the nine months ended September 30, 2022. In the first three quarters of 2023, we issued $250.0 million of long-term debt, and repaid $13.5 million of maturing long-term debt. This compared to $400.0 million of long-term debt issued in the first three quarters of 2022, of which we used a portion to repay $250.0 million of maturing long-term debt. We also decreased our short-term borrowings by $241.5 million in the nine months ended September 30, 2023, compared to $16.0 million in the nine months ended September 30, 2022. In addition, we issued $88.2 million of common stock and paid $105.2 million in dividends in 2023, compared to issuing common stock of $93.0 million and paying $96.3 million in dividends in 2022.

### 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, 2023 and December 31, 2022 (dollars in thousands):

|  | September 30, 2023 Amount | Percent of total | December 31, 2022 Amount | Percent of total |
| --- | ---: | ---: | ---: | ---: |
| Current portion of long-term debt and leases | $7,835 | 0.1% | $21,084 | 0.4% |
| Short-term borrowings | 221,500 | 4.2% | 463,000 | 8.8% |
| Long-term debt to affiliated trusts | 51,547 | 1.0% | 51,547 | 1.0% |
| Long-term debt and leases | 2,637,249 | 49.5% | 2,387,792 | 45.4% |
| Total debt | 2,918,131 | 54.8% | 2,923,423 | 55.6% |
| Total shareholders’ equity | 2,409,887 | 45.2% | 2,334,668 | 44.4% |
| Total | $5,328,018 | 100.0% | $5,258,091 | 100.0% |

Our shareholders’ equity increased $75.2 million during the first three quarters of 2023 primarily due to net income and the issuance of common stock, which was partially offset by dividends paid.

We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements.

### 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).

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

In December 2022, we entered into a term loan, in the amount of $150 million with a maturity date of March 30, 2023. In March 2023, we repaid the $150 million outstanding balance on the term loan.

In December 2022, we entered into 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 September 30, 2023 (dollars in thousands):

|  | Amount of Facility | Borrowings Outstanding | Letters of Credit Outstanding (1) | Available Liquidity |
| --- | ---: | ---: | ---: | ---: |
| Line of Credit expiring June 2028 | $500,000 | $220,000 | $4,638 | $275,362 |
| Letter of Credit Facility | 50,000 | N/A | 9,000 | 41,000 |
| Total | $550,000 | $220,000 | $13,638 | $316,362 |

(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, 2023, we were in compliance 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 | 2023 | 2022 |
| --- | ---: | ---: |
| Maximum balance outstanding during the period | $334,500 | $292,000 |
| Average balance outstanding during the period | 239,073 | 175,672 |
| Average interest rate during the period | 5.91% | 2.13% |
| Average interest rate at end of the period | 6.42% | 3.85% |
| **$100 million line of credit, terminated June 2023** |  |  |
| Maximum balance outstanding during the period (1) | $15,000 | N/A |
| Average balance outstanding during the period (1) | 283 | N/A |
| Average interest rate during the period (1) | 7.75% | N/A |

(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, 2023, there was $1.5 million outstanding under this committed line of credit.

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, 2023, AEL&P was in compliance with this covenant with a ratio of 49.5 percent.

As of September 30, 2023, Avista Corp. and its subsidiaries were in compliance 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 9 of the Notes to Condensed Consolidated Financial Statements" for additional information regarding our short-term borrowing arrangements.

### Liquidity Expectations

During March 2023, we issued $250 million of long-term debt. We do not expect to issue any additional long-term debt in 2023. We expect to issue $120 million of common stock (including $88.2 million of common stock issued during the nine months ended September 30, 2023).

In 2024, we expect to issue $60 million of common stock, and $80 million of long-term debt.

### Capital Expenditures

We are making capital investments to enhance service and system reliability for our customers and replace aging infrastructure. We expect Avista Utilities' capital expenditures to be $475 million in 2023, $500 million in 2024, $525 million in 2025 and $550 million in 2026. See the 2022 Form 10-K for further information on our expected capital expenditures.

### Pension Plan

### Avista Utilities

In the nine months ended September 30, 2023 we contributed $10.0 million to the pension plan, and expect no further contributions for the year. We expect to contribute a total of $40.0 million to the pension plan in the period 2024 through 2027, 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 7 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, 2023 except as follows:

### Washington Climate Commitment Act (CCA)

The CCA establishes a cap and trade program to reduce greenhouse gas (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. We purchase allowances recorded as inventory, and record emissions obligations and emissions expense associated with sales. As allowances are used and retired, we remove both the inventory and emissions obligation from the balance sheet. 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 delivered in Washington but is allocated to Idaho customers (wholesale sales) or power generated in Washington that is ultimately delivered to Idaho customers. In May 2023, a model was approved for use in calculating the allowances needed for compliance that assumes hydroelectric generation is first used for wholesale sales, therefore reducing allowances required. As a result, the CCA is expected to have minimal financial impact on our electric operations in its initial years. 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. We are seeking regulatory approval to defer incremental costs related to our Washington and Idaho electric operations.

### Washington State Building Codes

In April 2022, the Washington State Building Code Council (SBCC) approved a revised energy code that requires 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, citing the Ninth Circuit’s recent decision in California Restaurant Association v. Berkeley.

On May 24, 2023, the SBCC voted to delay the effective date of the code amendments by 20 days and commenced an emergency rulemaking process to evaluate additional amendments to the code in light of the Berkeley decision. The SBCC has since further delayed the code amendments, and continued the rulemaking process, through March 15, 2024. As a result of this action, on July 18, 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 State Action remains pending.

See the 2022 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 2022 Form 10-K and have not materially changed during the nine months ended September 30, 2023. See the 2022 Form 10-K.

### Financial Risk

Our financial risks have not materially changed during the nine months ended September 30, 2023. Refer to the 2022 Form 10-K. The financial risks included below are required interim disclosures, even if they have not materially changed from December 31, 2022.

#### 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 6 of the Notes to Condensed Consolidated Financial Statements" for a summary of our interest rate swap derivatives outstanding as of September 30, 2023 and December 31, 2022 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 2022 Form 10-K for further information. As of September 30, 2023, we had interest rate swap derivatives outstanding with a notional amount totaling $30.0 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, 2023, we would not be required to post additional collateral because all of our outstanding interest rate swaps were in an asset position at the time.

As of September 30, 2023, we had cash deposited as collateral of $27.4 million and letters of credit of $9.0 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 2022 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, 2023 (including contracts considered derivatives and those considered non-derivatives), we would potentially be required to post the following additional collateral (in thousands):

|  | September 30, 2023 |
| --- | ---: |
| Additional collateral taking into account contractual thresholds | $8,900 |
| Additional collateral without contractual thresholds | 14,410 |

### Energy Commodity Risk

Our energy commodity risks have not materially changed during the nine months ended September 30, 2023. See the 2022 Form 10-K. The following table presents energy commodity derivative fair values as a net asset or (liability) as of September 30, 2023 expected to settle in each respective year (dollars in thousands). There are 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) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Remainder 2023 | $369 | $— | $(564) | $(8,324) | $372 | $1,192 | $(3,202) | $(7,104) |
| 2024 | 593 | — | (1,703) | (12,264) | 230 | 423 | (8,246) | (11,970) |
| 2025 | — | — | (1,499) | (1,966) | — | 296 | (3,925) | (1,246) |
| 2026 | — | — | (262) | (59) | — | — | — | — |

The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2022 expected to be delivered in each respective year (dollars in thousands). There were no expected deliveries of energy commodity derivatives after 2025.

| 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) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2023 | $1,120 | $— | $(33,150) | $62,753 | $(2,374) | $(20,018) | $17,166 | $(137,585) |
| 2024 | — | — | 162 | (3,879) | — | — | (4,968) | (5,790) |
| 2025 | — | — | 135 | (220) | — | — | (2,924) | (701) |

(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

#### 2023 Natural Gas Integrated Resource Plan

In March 2023, we filed our 2023 Natural Gas Integrated Resource Plan (IRP) with the WUTC, IPUC and OPUC. The state commissions review the IRPs and give the public the opportunity to comment. The state commissions do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.

Highlights of the 2023 Natural Gas IRP include the following:

- We anticipate having sufficient natural gas resources to meet expected loads, including in Idaho where customer growth is highest, with our current transportation contracts for natural gas.
- Customer forecasts are increasingly difficult to model due to a variety of recently passed rules and codes, including building code updates in Washington.
- Emissions compliance with the CCA in Washington and Climate Protection Plan in Oregon greatly impact our resource strategy, including the use of renewable natural gas, synthetic methane, and credits or allowances.
- Our Idaho preferred resource strategy continues to utilize a least cost basis.

We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.

We are required to file a natural gas IRP every two years and we anticipate our next IRP to be filed in 2025.

#### 2023 Electric Integrated Resource Plan

In June 2023, we filed our 2023 Electric IRP with the WUTC and IPUC. The state commissions review the IRPs and give the public the opportunity to comment. The state commissions do not approve or disapprove of the content in the IRPs; rather they acknowledge the IRPs are prepared in accordance with applicable standards.

Highlights of the 2023 Electric IRP include the following:

- The forecast for growth in energy requirements is 0.9 percent per year, higher than the 0.2 percent annual growth rate in the 2021 IRP. Higher growth largely reflects higher residential and commercial electric vehicle forecasts and new building electrification.
- We announced several resource acquisitions and an expected divestiture (Colstrip at the end of 2025) since our 2021 IRP.
- The resource strategy selected in the IRP is designed to achieve an 80 percent reduction in GHG emissions by 2045.
- We need long-duration storage to serve customers in peak hours after 2035.
- We created a Named Community Investment Fund to increase energy-related investments in disadvantaged communities. The fund will increase distributed energy resources such as energy efficiency, small-scale renewables, and energy storage.

We will monitor these assumptions on an on-going basis and adjust our resource requirements accordingly.

We are required to file an electric IRP every two years and we anticipate our next IRP to be filed in 2025.

## 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, 2023.

There have been no changes in the Company's internal control over financial reporting that occurred during the third quarter of 2023 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

## Risk factors

As filed, 3,126 characters.

Refer to the 2022 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 2022 Form 10-K with the exception of the following:

**Our technology may become obsolete, development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.**

Our technology may become obsolete before the end of its useful life. In addition, custom or new technology (including potential generative artificial intelligence) that is heavily relied upon by us or our counterparties may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Generative artificial intelligence could also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or licensing or use. Technology (including artificial intelligence) is also subject to intentional misuse (by criminals, terrorists or other bad actors). Technology failures or incidents of misuse could result in significant adverse effects on our operations, results of operations, financial condition and cash flows.

**Credit risk may be affected by industry concentration and geographic concentration.**

We have concentrations of suppliers and customers in the electric and natural gas industries including:

- electric and natural gas utilities,
- electric generators and transmission providers,
- oil and natural gas producers and pipelines,
- financial institutions including commodity clearing exchanges and related parties, and
- energy marketing and trading companies.

We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

We are a participant in the EIM, and engage in direct and indirect power purchase and sale transactions in connection with that participation. The EIM collateral posting requirements are based on established credit criteria, but there is no assurance the collateral will be sufficient to cover obligations that counterparties may owe each other in the EIM and any such credit losses could be allocated among all EIM participants, including us. A significant failure of a participant in the EIM to make payments when due on its obligations could have a ripple effect on our counterparties in the power and gas markets if those counterparties experience ancillary liquidity issues, and could generally result in a decline in the ability of our counterparties to perform on their obligations.

Filed Nov 1, 2023.
Source: SEC EDGAR, the filing index for accession 0000950170-23-057042. Last ingested by Listed: Oct 24, 2026, 14:55 ET. No prices; not investment advice.