UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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FOR THE QUARTERLY PERIOD ENDED |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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FOR THE TRANSITION PERIOD FROM TO |
Commission file number
(Exact name of Registrant as specified in its charter)
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer |
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code:
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
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Trading Symbol(s) |
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Name of Each Exchange on Which Registered |
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Accelerated filer |
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Non-accelerated filer |
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Smaller reporting company |
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Emerging growth company |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ☐ No
As of October 31, 2024,
AVISTA CORPORATION
INDEX
i
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Results of Operations - Alaska Electric Light and Power Company |
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61 |
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61 |
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61 |
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61 |
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61 |
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61 |
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62 |
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63 |
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64 |
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64 |
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66 |
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Item 3. |
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67 |
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Item 4. |
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67 |
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Item 1. |
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69 |
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Item 1A. |
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69 |
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Item 5. |
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69 |
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Item 6. |
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70 |
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71 |
ii
ACRONYMS AND TERMS
(The following acronyms and terms are found in multiple locations within the document)
Acronym/Term |
Meaning |
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aMW |
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Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time |
AEL&P |
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Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska |
AERC |
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Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska |
AFUDC |
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Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period |
ASC |
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Accounting Standards Codification |
ASU |
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Accounting Standards Update |
Avista Capital |
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Parent company to the Company’s non-utility businesses, with the exception of AJT Mining Properties, Inc., which is a subsidiary of AERC. |
Avista Corp. |
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Avista Corporation, the Company |
Avista Utilities |
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Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest |
Capacity |
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The rate at which a particular generating source is capable of producing energy, measured in KW or MW |
Cabinet Gorge |
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The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho |
CCA |
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Climate Commitment Act |
CETA |
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Clean Energy Transformation Act |
Colstrip |
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The coal-fired Colstrip Generating Plant in southeastern Montana |
Cooling degree days |
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The measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures) |
COVID-19 |
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Coronavirus disease 2019, a respiratory illness declared a pandemic in March 2020 |
Deadband or ERM |
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The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington |
Ecology |
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The Washington State Department of Ecology |
EIM |
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Energy Imbalance Market |
Energy |
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The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms |
EPA |
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Environmental Protection Agency |
ERM |
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The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington |
FASB |
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Financial Accounting Standards Board |
FCA |
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Fixed Cost Adjustment, the electric and natural gas decoupling mechanism in Idaho |
FERC |
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Federal Energy Regulatory Commission |
GAAP |
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Generally Accepted Accounting Principles |
GHG |
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Greenhouse gas |
Heating degree days |
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The measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). |
IPUC |
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Idaho Public Utilities Commission |
iii
KW, KWh |
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Kilowatt (1000 watts): a measure of generating power or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced over a period of time |
MPSC |
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Public Service Commission of the State of Montana |
MW, MWh |
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Megawatt: 1000 KW. Megawatt-hour: 1000 KWh |
Noxon Rapids |
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The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana |
OPUC |
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The Public Utility Commission of Oregon |
PCA |
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The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho |
PGA |
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Purchased Gas Adjustment |
PPA |
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Power Purchase Agreement |
RCA |
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The Regulatory Commission of Alaska |
REC |
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Renewable energy credit |
ROE |
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Return on equity |
ROR |
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Rate of return on rate base |
ROU |
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Right-of-use lease asset |
SEC |
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U.S. Securities and Exchange Commission |
SOFR |
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Secured Overnight Financing Rate |
Talen |
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Talen Montana, LLC, an indirect subsidiary of Talen Energy Corporation. |
Therm |
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Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) |
Watt |
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Unit of measurement of electric power or capability; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt |
WUTC |
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Washington Utilities and Transportation Commission |
iv
Forward-Looking Statements
From time to time, we make forward-looking statements such as statements regarding projected or future:
These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Quarterly Report on Form 10-Q), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.
Forward-looking statements (including those made in this Quarterly Report on Form 10-Q) are subject to a variety of risks, uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:
Utility Regulatory Risk
Operational Risk
1
2
Climate Change Risk
Cybersecurity Risk
Technology Risk
Strategic Risk
3
External Mandates Risk
Financial Risk
4
Energy Commodity Risk
Compliance Risk
Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. There can be no assurance our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.
Available Information
We file annual, quarterly and current reports and proxy statements with the SEC. The SEC maintains a website that contains these documents at www.sec.gov. We make annual, quarterly and current reports and proxy statements available on our website, https://investor.avistacorp.com, as soon as practicable after electronically filing these documents with the SEC. Except for SEC filings or portions thereof specifically referred to in this report, information contained on these websites is not part of this report.
5
PART I. Financial Information
Item 1. Condensed Consolidated Financial Statements
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands, except per share amounts
(Unaudited)
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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2024 |
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2023 |
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2024 |
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2023 |
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Operating Revenues: |
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Utility revenues: |
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Utility revenues, exclusive of alternative revenue programs |
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$ |
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$ |
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$ |
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Alternative revenue programs |
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Total utility revenues |
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Non-utility revenues |
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Total operating revenues |
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Operating Expenses: |
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Utility operating expenses: |
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Resource costs |
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Other operating expenses |
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Depreciation and amortization |
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Taxes other than income taxes |
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Non-utility operating expenses |
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Total operating expenses |
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Income from operations |
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Interest expense |
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Interest expense to affiliated trusts |
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Capitalized interest |
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Other income-net |
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Income before income taxes |
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Income tax expense (benefit) |
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( |
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( |
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Net income |
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$ |
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$ |
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$ |
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$ |
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Weighted-average common shares outstanding (thousands), basic |
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Weighted-average common shares outstanding (thousands), diluted |
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Earnings per common share: |
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Basic |
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$ |
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$ |
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$ |
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$ |
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Diluted |
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$ |
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$ |
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$ |
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$ |
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The Accompanying Notes are an Integral Part of These Statements.
6
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands
(Unaudited)
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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2024 |
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2023 |
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2024 |
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2023 |
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Net income |
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$ |
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$ |
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$ |
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$ |
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Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of ($ |
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Comprehensive income |
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$ |
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$ |
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$ |
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$ |
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The Accompanying Notes are an Integral Part of These Statements.
7
CONDENSED CONSOLIDATED BALANCE SHEETS
Avista Corporation
Dollars in thousands
(Unaudited)
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September 30, |
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December 31, |
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2024 |
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2023 |
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Assets: |
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Current Assets: |
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Cash and cash equivalents |
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$ |
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$ |
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Accounts and notes receivable-less allowances of $ |
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Inventory |
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Regulatory assets |
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Other current assets |
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Total current assets |
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Net utility property |
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Goodwill |
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Non-current regulatory assets |
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Other property and investments-net and other non-current assets |
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Total assets |
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$ |
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$ |
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Liabilities and Equity: |
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Current Liabilities: |
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Accounts payable |
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$ |
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$ |
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Current portion of long-term debt |
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Short-term borrowings |
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Regulatory liabilities |
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Other current liabilities |
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Total current liabilities |
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Long-term debt |
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Long-term debt to affiliated trusts |
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Pensions and other postretirement benefits |
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Deferred income taxes |
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Non-current regulatory liabilities |
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Other non-current liabilities and deferred credits |
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Total liabilities |
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and (See Notes to Condensed Consolidated |
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Equity: |
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Shareholders’ Equity: |
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Common stock, |
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Accumulated other comprehensive loss |
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Retained earnings |
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Total shareholders’ equity |
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Total liabilities and equity |
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$ |
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$ |
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The Accompanying Notes are an Integral Part of These Statements.
8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands
(Unaudited)
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2024 |
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2023 |
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Operating Activities: |
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Net income |
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$ |
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$ |
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Non-cash items included in net income: |
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Depreciation and amortization |
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Deferred income tax provision |
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( |
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Power and natural gas cost deferrals, net |
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Amortization of debt expense |
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Stock-based compensation expense |
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Equity-related AFUDC |
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Pension and other postretirement benefit expense |
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Other regulatory assets and liabilities |
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Other deferred debits and credits |
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Change in decoupling regulatory deferral |
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Realized and unrealized losses on assets |
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Other |
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( |
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( |
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Contributions to defined benefit pension plan |
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( |
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( |
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Cash paid for settlement of interest rate swap agreements |
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— |
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( |
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Cash received for settlement of interest rate swap agreements |
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Changes in certain current assets and liabilities: |
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Accounts and notes receivable |
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Inventory |
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( |
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Collateral for derivative instruments |
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Income taxes receivable |
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( |
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Other current assets |
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( |
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Accounts payable |
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( |
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( |
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Other current liabilities |
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Net cash provided by operating activities |
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Investing Activities: |
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Utility property capital expenditures (excluding equity-related AFUDC) |
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( |
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( |
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Investments made in equity and property |
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( |
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( |
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Proceeds from sale of investments |
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— |
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Other |
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( |
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Net cash used in investing activities |
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( |
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( |
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The Accompanying Notes are an Integral Part of These Statements.
9
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Avista Corporation
For the Nine Months Ended September 30
Dollars in thousands
(Unaudited)
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2024 |
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2023 |
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Financing Activities: |
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Net decrease in short-term borrowings |
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$ |
( |
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$ |
( |
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Proceeds from issuance of long-term debt |
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Maturity of long-term debt and finance leases |
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( |
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( |
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Issuance of common stock, net of issuance costs |
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Cash dividends paid |
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( |
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( |
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Other |
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( |
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( |
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Net cash used in financing activities |
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( |
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( |
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Net decrease in cash and cash equivalents |
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( |
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( |
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Cash and cash equivalents at beginning of period |
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Cash and cash equivalents at end of period |
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$ |
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$ |
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The Accompanying Notes are an Integral Part of These Statements.
10
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
Avista Corporation
For the Three and Nine Months Ended September 30
Dollars in thousands
(Unaudited)
|
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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||||||||||
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2024 |
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2023 |
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2024 |
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2023 |
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Common Stock, Shares: |
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|
||||
Shares outstanding at beginning of period |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Shares issued |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Shares outstanding at end of period |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Common Stock, Amount: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Balance at beginning of period |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Equity compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Issuance of common stock, net of issuance costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Payment of minimum tax withholdings for share-based payment awards |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Balance at end of period |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accumulated Other Comprehensive Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Balance at beginning of period |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Other comprehensive loss |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Balance at end of period |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Retained Earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Balance at beginning of period |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Dividends on common stock |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Balance at end of period |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total equity |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Dividends declared per common share |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
The Accompanying Notes are an Integral Part of These Statements.
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
The accompanying condensed consolidated financial statements of Avista Corp. as of and for the interim periods ended September 30, 2024 and September 30, 2023 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. All such adjustments are of a normal recurring nature. The condensed consolidated financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2023 (2023 Form 10-K).
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising its regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana.
AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, which comprises Avista Corp.'s regulated utility operations in Alaska.
Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of the subsidiary companies in the non-utility businesses, except AJT Mining Properties, Inc., which is a subsidiary of AERC. See Note 16 for business segment information.
Basis of Reporting
The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations associated with its interests in jointly owned plants.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Condensed Consolidated Balance Sheets measured at estimated fair value.
The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rate cases. The resulting regulatory assets associated with energy commodity derivative instruments are probable of recovery through future rates.
12
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts not considered derivatives are accounted for on the accrual basis until they are settled or realized unless there is a decline in the fair value of the contract determined to be other-than-temporary.
For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process.
The Company has multiple master netting agreements with a variety of entities allowing for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap derivatives for the same counterparty. The Company does not have agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Condensed Consolidated Balance Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, some equity investments, as well as derivatives related to interest rate swaps and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. See Note 11 for the Company’s fair value disclosures.
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses loss contingencies that do not meet these conditions for accrual if there is a reasonable possibility that a material loss may be incurred. See Note 15 for further discussion of the Company's commitments and contingencies.
NOTE 2. NEW ACCOUNTING STANDARDS
ASU 2022-03 "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions"
In June 2022, the FASB issued ASU 2022-03, Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions. The purpose of this guidance is to clarify that a contractual restriction on the ability to sell an equity security is not considered part of the unit of account of the equity security, and therefore should not be considered when measuring the equity security's fair value. Additionally, an entity cannot separately recognize and measure a contractual sale restriction. This guidance also adds specific disclosures related to equity securities subject to contractual sale restrictions, including (i) the fair value of equity securities subject to contractual sale restrictions reflected in the balance sheet, (ii) the nature and remaining duration of the restrictions and (iii) the circumstances that could cause a lapse in the restrictions. The Company
ASU 2023-06 "Disclosure Improvements - Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative"
In October 2023, the FASB issued ASU 2023-06, which incorporates a variety of SEC required disclosures into the FASB Accounting Standards Codification (ASC). For entities subject to SEC's existing disclosure requirements, the effective date for each amendment will be the date on which the SEC removes the related disclosure from Regulation S-X or Regulation S-K, with early adoption permitted. If the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K by June 30, 2027, the
13
disclosure requirements will be removed from the Codification. The requirements of the ASU will not have a material impact on the Company's financial statements.
ASU 2023-07 "Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures"
In November 2023, the FASB issued ASU 2023-07, requiring additional disclosures around reportable segment information. The additional required disclosures include significant segment expenses, an amount for other segment activity not included in the disaggregated segment amounts and a description of the activity, and the title and position of the chief operating decision maker and an explanation of how they use the reported measures of segment profit or loss in assessing segment performance and allocating resources. The ASU is effective for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024, and early adoption is permitted. The Company expects the implementation of the ASU to result in expanded segment reporting disclosures.
ASU 2023-09 "Income Taxes (Topic 740) - Improvements to Income Tax Disclosures"
In December 2023, the FASB issued ASU 2023-09, requiring additional income tax disclosures. The additional disclosures include prescribed items presented in the income tax rate reconciliation, and further disaggregation of income taxes paid amounts between federal, state and foreign taxes. The ASU is effective for fiscal years beginning after December 15, 2024 and early adoption is permitted. The Company expects the implementation of the ASU to result in expanded income tax disclosures.
NOTE 3. BALANCE SHEET COMPONENTS
Inventory
Inventories of materials and supplies, emission allowances, fuel stock and stored natural gas are recorded at average cost and consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Materials and supplies |
|
$ |
|
|
$ |
|
||
Emission allowances |
|
|
|
|
|
|
||
Stored natural gas |
|
|
|
|
|
|
||
Fuel stock |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
Other Current Assets
Other current assets consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Prepayments |
|
$ |
|
|
$ |
|
||
Income taxes receivable |
|
|
|
|
|
|
||
Derivative assets net of collateral |
|
|
|
|
|
|
||
Collateral posted for derivative instruments after netting with outstanding |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
14
Net Utility Property
Net utility property, which is recorded at original cost, net of accumulated depreciation, consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Utility plant in service |
|
$ |
|
|
$ |
|
||
Construction work in progress |
|
|
|
|
|
|
||
Total |
|
|
|
|
|
|
||
Less: Accumulated depreciation and amortization |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
Other Property and Investments-Net and Other Non-Current Assets
Other property and investments-net and other non-current assets consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Equity investments |
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|||
|
|
|
|
|
|
|||
Non-utility property |
|
|
|
|
|
|
||
Notes receivable |
|
|
|
|
|
|
||
Long-term prepaid license fees |
|
|
|
|
|
|
||
Pension asset |
|
|
|
|
|
|
||
Investment in affiliated trust |
|
|
|
|
|
|
||
Deferred compensation assets |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
Other Current Liabilities
Other current liabilities consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
Accrued taxes other than income taxes |
|
$ |
|
|
$ |
|
||
Derivative liabilities net of collateral |
|
|
|
|
|
|
||
Employee paid time off accruals |
|
|
|
|
|
|
||
Accrued interest |
|
|
|
|
|
|
||
Climate Commitment Act obligations |
|
|
|
|
|
|
||
Pensions and other postretirement benefits |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
15
Other Non-Current Liabilities and Deferred Credits
Other non-current liabilities and deferred credits consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
$ |
|
|
$ |
|
|||
Finance lease liabilities |
|
|
|
|
|
|
||
Deferred investment tax credits |
|
|
|
|
|
|
||
Climate Commitment Act obligations |
|
|
|
|
|
|
||
Asset retirement obligations |
|
|
|
|
|
|
||
Derivative liabilities net of collateral |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
Regulatory Assets and Liabilities
Regulatory assets and liabilities consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, 2024 |
|
|
December 31, 2023 |
|
||||||||||
|
|
Current |
|
|
Non-Current |
|
|
Current |
|
|
Non-Current |
|
||||
Regulatory Assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Energy commodity derivatives |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Deferred Climate Commitment Act costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferred power costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Wildfire resiliency |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Decoupling surcharge |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferred natural gas costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Income tax related assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Pension and other postretirement benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest rate swaps |
|
|
|
|
|
|
|
|
|
|
|
|
||||
AFUDC above FERC allowed rate |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Settlement with Coeur d'Alene Tribe |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Advanced meter infrastructure |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Utility plant abandoned |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Colstrip excess depreciation |
|
|
|
|
|
|
|
|
|
|
|
|
||||
COVID-19 deferrals |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Demand side management programs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other regulatory assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total regulatory assets |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Regulatory Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other income tax related liabilities |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Excess deferred income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferred Climate Commitment Act revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferred power costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferred natural gas costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Decoupling rebate |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Utility plant retirement costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest rate swaps |
|
|
|
|
|
|
|
|
|
|
|
|
||||
COVID-19 deferrals |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other regulatory liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total regulatory liabilities |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
16
NOTE 4. REVENUE
The core principle of the revenue recognition model is that an entity should identify the various performance obligations in a contract, allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each performance obligation.
Utility Revenues
Revenue from Contracts with Customers
General
The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the Company may bill the customer. Since all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately.
Revenues from contracts with customers are presented in the Condensed Consolidated Statements of Income in the line item "Utility revenues, exclusive of alternative revenue programs."
Non-Derivative Wholesale Contracts
The Company has certain wholesale contracts that are not accounted for as derivatives and are considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is available for a specified period of time, consistent with the discussion of rate-regulated sales above.
Alternative Revenue Programs (Decoupling)
Alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between an entity and a customer. GAAP requires the presentation of revenue arising from alternative revenue programs separately from revenues arising from contracts with customers on the Condensed Consolidated Statements of Income. The Company's decoupling mechanisms (also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the Condensed Consolidated Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset or liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for an alternative revenue program, like decoupling, the revenue must be expected to be collected from customers within 24 months of the deferral to qualify for recognition in the Condensed Consolidated Statements of Income. Amounts included in the Company's decoupling program that are not expected to be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. The amounts expected to be collected from customers within 24 months represents an estimate made by the Company on an ongoing basis due to it being based on the volumes of electric and natural gas sold to customers on a go-forward basis.
The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory asset/liability to the alternative revenue program line item on the Condensed Consolidated Statements of Income as it is collected from or refunded to customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the year.
17
Derivative Revenue
Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are considered derivatives, which are disclosed separately from revenue from contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative revenue includes transactions entered into and settled within the same month.
Other Utility Revenue
Other utility revenue includes rent, sales of materials, late fees and other charges that do not represent contracts with customers. This revenue is excluded from revenue from contracts with customers, as this revenue does not represent items where a customer contracted with the Company to obtain goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are presented separately from revenue from contracts with customers.
Other Considerations for Utility Revenues
Gross Versus Net Presentation
Revenues and resource costs from Avista Utilities’ settled energy contracts “booked out” (not physically delivered) are reported on a net basis as part of derivative revenues.
Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are imposed on Avista Utilities as opposed to being imposed on customers; therefore, Avista Utilities is the taxpayer and records these transactions on a gross basis in revenue from contracts with customers and operating expense (taxes other than income taxes). The utility-related taxes collected from customers at AEL&P are imposed on the customers rather than AEL&P; therefore, the customers are the taxpayers and AEL&P is acting as their agent. As such, these transactions at AEL&P are presented on a net basis within revenue from contracts with customers.
Utility-related taxes included in revenue from contracts with customers were as follows for the three and nine months ended September 30 (dollars in thousands):
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
Utility-related taxes |
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
Significant Judgments and Unsatisfied Performance Obligations
The only significant judgments involving revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers and estimates surrounding the amount of decoupling revenues that will be collected from customers within 24 months (discussed above).
The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in deferred revenue and only result in receivables from the customers. The Company has one capacity agreement where the customer makes payments throughout the year. As of September 30, 2024, the Company estimates it had unsatisfied capacity performance obligations of $
18
Disaggregation of Total Operating Revenue
The following table disaggregates total operating revenue by segment and source for the three and nine months ended September 30 (dollars in thousands):
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
Avista Utilities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenue from contracts with customers |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Derivative revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Alternative revenue programs |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|||
Other utility revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total Avista Utilities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
AEL&P |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenue from contracts with customers |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Deferrals and amortizations for rate refunds to customers |
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
Other utility revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total AEL&P |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other non-utility revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
Utility Revenue from Contracts with Customers by Type and Service
The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the three and nine months ended September 30 (dollars in thousands):
|
|
2024 |
|
|
2023 |
|
||||||||||||||||||
|
|
Avista |
|
|
AEL&P |
|
|
Total Utility |
|
|
Avista |
|
|
AEL&P |
|
|
Total Utility |
|
||||||
Three months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
ELECTRIC OPERATIONS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Revenue from contracts with customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Residential |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Commercial |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Industrial |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Public street and highway lighting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total retail revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Transmission |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Other revenue from contracts with |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Total electric revenue from contracts |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Nine months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
ELECTRIC OPERATIONS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Revenue from contracts with customers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Residential |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Commercial |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Industrial |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Public street and highway lighting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total retail revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Transmission |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Other revenue from contracts with |
|
|
|
|
|
— |
|
|
|
|
|
|
|
|
|
— |
|
|
|
|
||||
Total electric revenue from contracts |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
19
The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for the three and nine months ended September 30 (dollars in thousands):
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
|
|
Avista Utilities |
|
|
Avista Utilities |
|
|
Avista Utilities |
|
|
Avista Utilities |
|
||||
NATURAL GAS OPERATIONS |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenue from contracts with customers |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Residential |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Commercial |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Industrial and interruptible |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total retail revenue |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Transportation |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other revenue from contracts with customers |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total natural gas revenue from contracts with customers |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options, to manage the various risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage these risks.
As part of Avista Corp.'s resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions. These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion of the related financial risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. Based on these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as three natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak-day. Avista Corp. optimizes its natural gas resources by using market opportunities to generate economic value that mitigates the fixed costs. Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and prices indicate that Avista Corp. should buy or sell natural gas at other times during the year, Avista Corp. engages in optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage capacity, and participation in the transportation capacity release market.
20
The following table presents the underlying energy commodity derivative volumes as of September 30, 2024 expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
|
|
Purchases |
|
|
Sales |
|
||||||||||||||||||||||||||
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
||||||||||||||||||||
Year |
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
||||||||
Remainder 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
2027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2024, there were
The following table presents the underlying energy commodity derivative volumes as of December 31, 2023 expected to be delivered in each respective year (in thousands of MWhs and mmBTUs):
|
|
Purchases |
|
|
Sales |
|
||||||||||||||||||||||||||
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
||||||||||||||||||||
Year |
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
|
Physical |
|
|
Financial |
|
||||||||
2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2023, there were
The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are scheduled to be delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA and PGAs), or in the general rate case process, and are expected to be recovered through retail rates from customers.
Foreign Currency Exchange Derivatives
A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are settled within
The following table summarizes the foreign currency exchange derivatives outstanding as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Number of contracts |
|
|
|
|
|
|
||
Notional amount (in United States dollars) |
|
$ |
|
|
$ |
|
||
Notional amount (in Canadian dollars) |
|
|
|
|
|
|
21
Interest Rate Swap Derivatives
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista Corp. may hedge a portion of its interest rate risk with financial derivative instruments, including interest rate swap derivatives. These interest rate swap derivatives are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances.
The following table summarizes the unsettled interest rate swap derivatives outstanding as of September 30, 2024 and December 31, 2023 (dollars in thousands):
Balance Sheet Date |
|
Number of |
|
|
Notional |
|
|
Mandatory |
||
September 30, 2024 |
|
|
|
|
$ |
|
|
|||
December 31, 2023 |
|
|
|
|
$ |
|
|
|||
|
|
|
|
|
|
|
|
See Note 9 for discussion of the remarketed bonds and the related settlement of interest rate swaps in connection with the pricing of the bonds in March 2024.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Condensed Consolidated Balance Sheet as of September 30, 2024 and December 31, 2023 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists.
The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2024 (in thousands):
|
|
Fair Value |
|
|||||||||||||
Derivative and Balance Sheet Location |
|
Gross |
|
|
Gross |
|
|
Collateral |
|
|
Net Asset |
|
||||
Foreign currency exchange derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
||
Interest rate swap derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other non-current liabilities and deferred credits |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Energy commodity derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets |
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
|
||
Other property and investments-net and other non-current assets |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other current liabilities |
|
|
|
|
|
( |
) |
|
|
|
|
|
( |
) |
||
Other non-current liabilities and deferred credits |
|
|
|
|
|
( |
) |
|
|
|
|
|
( |
) |
||
Total derivative instruments recorded on the balance sheet |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
22
The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2023 (in thousands):
|
|
Fair Value |
|
|||||||||||||
Derivative and Balance Sheet Location |
|
Gross |
|
|
Gross |
|
|
Collateral |
|
|
Net Asset |
|
||||
Foreign currency exchange derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
||
Interest rate swap derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other non-current liabilities and deferred credits |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Energy commodity derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other current assets |
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
|
||
Other current liabilities |
|
|
|
|
|
( |
) |
|
|
|
|
|
( |
) |
||
Other non-current liabilities and deferred credits |
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
Total derivative instruments recorded on the balance sheet |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
Exposure to Demands for Collateral
Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement. In the event of changes in market prices or a downgrade in Avista Corp.'s credit ratings or other established credit criteria, additional collateral may be required. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.
The following table presents collateral outstanding related to its derivative instruments as of September 30, 2024 and December 31, 2023 (in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Energy commodity derivatives |
|
|
|
|
|
|
||
Cash collateral posted |
|
$ |
|
|
$ |
|
||
Letters of credit outstanding |
|
|
|
|
|
|
Certain of Avista Corp.’s derivative instruments contain provisions that require Avista Corp. to maintain an "investment grade" credit rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of energy commodity derivative instruments with credit-risk-related contingent features in a liability position and the amount of additional collateral Avista Corp. could be required to post as of September 30, 2024 (in thousands):
|
|
September 30, |
|
|
|
|
2024 |
|
|
Energy commodity derivatives |
|
|
|
|
Liabilities with credit-risk-related contingent features |
|
$ |
|
|
Additional collateral to post |
|
|
|
As of September 30, 2024, there are no material interest rate swap derivative instruments with credit-risk-related contingent features in a liability position.
23
NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
Avista Utilities
The Company contributed $
The Company uses a December 31 measurement date for its defined benefit pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three and nine months ended September 30 (dollars in thousands):
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
Three months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Service cost |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Interest cost |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Expected return on plan assets |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Amortization of prior service cost (credit) |
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
||
Net loss recognition |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|||
Net periodic benefit cost |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Nine months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Service cost |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Interest cost |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Expected return on plan assets |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Curtailment loss |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Amortization of prior service cost (credit) |
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
||
Net loss recognition |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net periodic benefit cost |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is recorded to various projects based on whether the work is a capital project or an operating expense. Approximately
The non-service portion of costs in the table above are recorded to other expense below income from operations in the Condensed Consolidated Statements of Income or capitalized as a regulatory asset. Approximately
In 2024, the Company offered pension participants an election to leave the pension plan for an alternative defined contribution 401(k) plan. In April 2024, it was determined that due to the number of participants electing to leave the pension plan, as well as the resulting decrease in expected future service, this event resulted in a curtailment of the pension plan, and an associated gain of $
24
NOTE 7. INCOME TAXES
In accordance with interim reporting requirements, the Company uses an estimated annual effective tax rate for computing its provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, accounting method changes or adjustments to tax expense or benefits attributable to prior years. Discrete events are recorded in the interim period in which they occur or become known. The estimated annual tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period’s year-to-date amount.
The following table summarizes the significant factors impacting the difference between the Company's effective tax rate and the federal statutory rate for the three and nine months ended September 30 (dollars in thousands):
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||||||||||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||||||||||||||||||
Federal income taxes at statutory rates |
|
$ |
|
|
|
% |
|
$ |
|
|
|
% |
|
$ |
|
|
|
% |
|
$ |
|
|
|
% |
||||||||
Increase (decrease) in tax resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Flow through related to deduction of meters |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Tax effect of regulatory treatment of utility |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
State income tax expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Tax credits |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Other |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total income tax expense (benefit) |
|
$ |
( |
) |
|
|
( |
)% |
|
$ |
( |
) |
|
|
( |
)% |
|
$ |
|
|
|
% |
|
$ |
( |
) |
|
|
( |
)% |
NOTE 8. SHORT-TERM BORROWINGS
Avista Corp.
Lines of Credit
Avista Corp. has a committed line of credit in the total amount of $
Balances outstanding and interest rates on borrowings (excluding letters of credit) under Avista Corp.’s revolving committed line of credit were as follows as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Borrowings outstanding at end of period |
|
$ |
|
|
$ |
|
||
Letters of credit outstanding at end of period |
|
|
|
|
|
|
||
Average interest rate on borrowings at end of period |
|
|
% |
|
|
% |
25
Letter of Credit Facility
Avista Corp. has a letter of credit agreement in the aggregate amount of $
Avista Corp. had $
Covenants and Default Provisions
The short-term borrowing agreements contain customary covenants 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 the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than
AEL&P
AEL&P has a committed line of credit in the amount of $
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has 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 bonds to be greater than
NOTE 9. LONG-TERM DEBT
In April 2024, the Company closed on the remarketing of $
In connection with the pricing of the Forsyth bonds in March 2024, the Company cash-settled
The net proceeds from the remarketing of the Forsyth bonds were used to repay a portion of the borrowings outstanding under the Company's committed line of credit.
NOTE 10. LONG-TERM DEBT TO AFFILIATED TRUSTS
In
26
The distribution rates were as follows during the nine months ended September 30, 2024 and the year ended December 31, 2023:
|
|
September 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Low distribution rate |
|
|
% |
|
|
% |
||
High distribution rate |
|
|
% |
|
|
% |
||
Distribution rate at the end of the period |
|
|
% |
|
|
% |
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $
The Company owns
NOTE 11. FAIR VALUE
The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable, and short-term borrowings as shown on the Condensed Consolidated Balance Sheets are reasonable estimates of their fair values. The carrying values of long-term debt (including current portion and material finance leases) and long-term debt to affiliated trusts as shown on the Condensed Consolidated Balance Sheets may be different from the estimated fair value. See below for the estimated fair value of long-term debt and long-term debt to affiliated trusts.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to fair values derived from unobservable inputs (Level 3 measurements).
The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors including the credit standing of the counterparties involved and the impact
27
of credit enhancements (such as cash deposits and letters of credit), and the impact of Avista Corp.’s nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, 2024 |
|
|
December 31, 2023 |
|
||||||||||
|
|
Carrying |
|
|
Estimated |
|
|
Carrying |
|
|
Estimated |
|
||||
Long-term debt (Level 2) |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Long-term debt (Level 3) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Snettisham finance lease obligation (Level 3) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Long-term debt to affiliated trusts (Level 3) |
|
|
|
|
|
|
|
|
|
|
|
|
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of market prices of
28
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023 at fair value on a recurring basis (dollars in thousands):
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Counterparty |
|
|
Total |
|
|||||
September 30, 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Energy commodity derivatives |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Equity Investments |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Deferred compensation assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Mutual Funds: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Fixed income securities (3) |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Equity securities (3) |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Energy commodity derivatives (2) |
|
$ |
— |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Interest rate swap derivatives |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total |
|
$ |
— |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
December 31, 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Energy commodity derivatives (2) |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
||
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
Interest rate swap derivatives |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Equity Investments |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Deferred compensation assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Mutual Funds: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Fixed income securities (3) |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Equity securities (3) |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Energy commodity derivatives (2) |
|
$ |
— |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Interest rate swap derivatives |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total |
|
$ |
— |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. See Note 5 for additional discussion of derivative netting.
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate the fair value of energy commodity derivative instruments included in Level 2. Electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
29
To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets.
Level 3 Fair Value
Natural Gas Exchange Agreement
For the natural gas commodity exchange agreement, the Company uses the same Level 2 market quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions are not highly correlated with market prices and market volatility.
The natural gas commodity exchange agreement expires in April 2025. The Company expects remaining transactions under the agreement will be sales.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of September 30, 2024 (dollars in thousands):
|
|
Fair Value |
|
|
Valuation |
|
Unobservable |
|
Range and Weighted |
|
|
|
September 30, 2024 |
|
|
Technique |
|
Input |
|
Average Price |
|
Natural gas exchange agreement |
|
$ |
( |
) |
|
Internally derived weighted average cost of gas |
|
Forward sales prices |
|
$ |
|
|
|
|
|
|
|
Sales volumes |
|
The valuation methods, significant inputs and resulting fair values described above were developed by the Company and are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate of fair value each reporting period.
Equity Investments
The Company has
For the second investment, the fair value is determined using an income approach utilizing a discounted cash flow model. The model is based on income statement forecasts from the underlying company to determine cash flows for the period of ownership. The model then utilizes market multiples from publicly traded comparable companies in similar industries and projects to estimate the terminal
30
fair value. The market multiples are reduced to reflect the difference in the life cycle between the publicly traded comparable companies and the start-up nature of the investment company. The selection of appropriate comparable companies, market multiples and the reduction to those market multiples requires management judgment. The significant assumptions in the model include the discount rate representing the risk associated with the investment, market multiples and the related reduction to those multiples, revenue forecasts, and the estimated terminal date for the investment. In the event there are relevant market transactions for the same or similar securities of the subject company or there is the reasonable possibility of a transaction occurring, those transactions are used to determine the fair value of Avista Corp.’s investment under a market approach instead of utilizing a discounted cash flow model. The market transactions are considered Level 3 inputs because they are not publicly available observable transactions.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 equity investments as of September 30, 2024 (dollars in thousands):
|
|
Fair Value at |
|
|
|
|
|
|
|
|
|
|
September 30, 2024 |
|
|
Valuation Technique |
|
Unobservable Input |
|
Range |
|
|
$ |
|
|
Market approach |
|
values |
|
$ |
||
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
Discounted cash flows |
|
|
|||
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
$ |
||
|
|
|
|
|
|
|
|
31
The following table presents activity for assets and liabilities measured at fair value using significant unobservable inputs (Level 3) for the three and nine months ended September 30 (dollars in thousands):
|
|
Natural Gas Exchange Agreement (1) |
|
|
Equity Investments |
|
|
Total |
|
|||
Three Months Ended September 30, 2024: |
|
|
|
|
|
|
|
|
|
|||
Beginning balance |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Total gains or (losses) (realized/unrealized): |
|
|
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities |
|
|
|
|
|
— |
|
|
|
|
||
|
|
— |
|
|
|
|
|
|
|
|||
Purchases and debt conversions |
|
|
— |
|
|
|
|
|
|
|
||
Settlements |
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
Ending balance as of September 30, 2024 |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Three Months Ended September 30, 2023: |
|
|
|
|
|
|
|
|
|
|||
Beginning balance |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Total gains or (losses) (realized/unrealized): |
|
|
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities |
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
|
|
|
|
|||
Ending balance as of September 30, 2023 |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Nine Months Ended September 30, 2024: |
|
|
|
|
|
|
|
|
|
|||
Beginning balance |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Total gains or (losses) (realized/unrealized): |
|
|
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities |
|
|
|
|
|
— |
|
|
|
|
||
|
|
— |
|
|
|
|
|
|
|
|||
Purchases and debt conversions |
|
|
— |
|
|
|
|
|
|
|
||
Settlements |
|
|
|
|
|
— |
|
|
|
|
||
Ending balance as of September 30, 2024 |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Nine Months Ended September 30, 2023: |
|
|
|
|
|
|
|
|
|
|||
Beginning balance |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Total gains or (losses) (realized/unrealized): |
|
|
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities |
|
|
|
|
|
— |
|
|
|
|
||
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
|
Purchases and debt conversions |
|
|
— |
|
|
|
|
|
|
|
||
Settlements |
|
|
|
|
|
— |
|
|
|
|
||
Other |
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Ending balance as of September 30, 2023 |
|
$ |
( |
) |
|
$ |
|
|
$ |
|
NOTE 12. COMMON STOCK
The Company issued shares of common stock for total net proceeds of $
NOTE 13. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2024 and December 31, 2023 (dollars in thousands):
|
|
September 30, |
|
|
December 31, |
|
||
Unfunded benefit obligation for pensions and other postretirement benefit plans - |
|
$ |
|
|
$ |
|
32
The following table details the reclassifications out of accumulated other comprehensive loss by component for the three and nine months ended September 30 (dollars in thousands):
|
|
Amounts Reclassified from Accumulated Other |
|
|||||||||||||
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||
Details about Accumulated Other Comprehensive Loss Components |
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
Amortization of defined benefit pension and |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Amortization of net prior service cost (1) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Amortization of net loss (1) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Adjustment due to effects of regulation (1) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total before tax (2) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Tax expense (2) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net of tax (2) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
The following table presents the computation of basic and diluted earnings per common share for the three and nine months ended September 30 (in thousands, except per share amounts):
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
||||
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net income |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted-average number of common shares outstanding-basic |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Performance and restricted stock awards |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted-average number of common shares outstanding-diluted |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Diluted |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
There were
NOTE 15. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company will vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the outcome of any matter because litigation and other contested proceedings are subject to numerous uncertainties. For matters affecting Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Climate Commitment Act (CCA)
The CCA requires the Company to submit greenhouse gas emission reports to the Washington State Department of Ecology (Ecology) annually for its electric and natural gas entities. The CCA then requires the Company to contract with a third-party verifier to audit the emissions data in the emissions reports. In August 2024, the Company’s third-party verifier submitted to Ecology its verification report on the Company’s 2023 emissions report. The verification report was issued with an adverse emissions data verification
33
statement. In September 2024, in the absence of a positive verification statement, Ecology assigned an emission level (AEL) to Avista Corp. based on information submitted by the Company’s third-party verifier.
The Company disagrees with the emissions assigned by Ecology as the amounts do not consider the application of the white paper entitled “Consideration of Electricity Imports and Determination of the Electricity Importer Under the Climate Commitment Act”, which was previously discussed with and agreed to in principle by Ecology. The third-party verifier was unable to apply the white paper as it couldn’t confirm with Ecology that the methodologies applied by the Company were consistent with the white paper before the initial reporting deadline. Ecology, the Company, and the third-party verifier have engaged in discussions regarding the proper application of the calculation methods identified in Ecology’s Greenhouse Gas Reporting Program and the white paper.
The Company has revised and re-submitted its emissions report to the third-party verifier and Ecology. The revised report makes certain adjustments identified by the verifier, but is otherwise consistent with the initial report regarding total emissions. The revised report has been reviewed by the third-party verifier, and the verifier has provided the Company written confirmation that it intends to issue a report with a positive emissions data verification statement in the fourth quarter of 2024. The revised report may result in an additional emissions liability of $
On October 31, 2024, Ecology agreed to stay the AEL issued in September 2024 for a period of
Collective Bargaining Agreements
The Company's collective bargaining agreement with the IBEW represents
The current agreement includes a clause to negotiate wages in effect for the last year of the agreement. On July 31, 2024, the IBEW voted to approve new wages for 2024 and 2025, with wages for 2024 effective retroactively to March 26, 2024 and wages for 2025 taking effect on January 1, 2025.
Boyds Fire (State of Washington Department of Natural Resources v. Avista)
In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v. Avista Corporation,” seeking recovery of up to $
34
The lawsuits were filed in the Superior Court of Ferry County, Washington, and is scheduled for trial on July 7, 2025. The Company continues to vigorously defend itself in the litigation. However, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Road 11 Fire
In April 2022, Avista Corp. received a notice of claim from property owners seeking damages of $
Labor Day 2020 Windstorm/ Babb Road Fire
In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in customer outages and multiple wildfires in the region, including the Babb Road Fire, which occurred near the town of Malden, Washington. The Babb Road Fire covered approximately
In May 2021 the Company learned the Washington Department of Natural Resources (DNR) had completed its investigation and issued a report on the Babb Road Fire.
The DNR report concluded, among other things, that
The DNR report concluded that: “because of the unusual configuration of the tree, and its proximity to the powerline, a closer inspection was warranted. A nearer inspection of the tree should have revealed the cut LBL ends and its previous failure, and necessitated determination of the failure potential of the adjacent LBL, implicated in starting the Babb Road Fire.”
The DNR report acknowledged that, other than the multi-dominant nature of the tree, the conditions mentioned above would not have been easily visible without close-up inspection of, or cutting into, the tree. The report also acknowledged that, while the presence of multiple tops would have been visible from the nearby roadway, the tree did not fail at a v-fork due to the presence of multiple tops. The Company contends that applicable inspection standards did not require a closer inspection of the otherwise healthy tree, nor was the Company negligent with respect to its maintenance, inspection or vegetation management practices.
Eleven lawsuits have been filed in connection with the Babb Road fire. Asplundh Tree Company and CN Utility Consulting, which both perform vegetation management services as independent contractors to the Company, are also named as defendants in each of the lawsuits. The lawsuits include
35
All proceedings, except for one action filed on September 1, 2023 on behalf of three individual plaintiffs (the "Widman Action") have been consolidated in the Superior Court of Spokane County Washington under the lead action Blakeley v. Avista Corporation et al., and variously assert causes of action for negligence, private nuisance, and trespass (the "Blakeley Proceeding").
In November 2023, all parties to the Blakeley Proceeding agreed to a stipulated order, which was presented to and entered by the Superior Court of Spokane County, Washington. The order consolidates the Blakeley Proceeding for trial (in addition to discovery and pre-trial proceedings) and bifurcates the trial into liability and damages phases, such that the initial trial in the case will focus solely on whether the defendants are legally responsible for the Babb Road Fire. A trial date on the liability phase has been set for May 5, 2025. The Widman Action is set for trial on October 6, 2025.
In addition, the stipulated order relating to the Blakeley Proceeding memorializes the plaintiffs' agreement to voluntarily dismiss all claims asserting inverse condemnation as a theory of liability, without prejudice to their ability to seek permission from the Court to refile those claims at a later date if they can show good cause to do so. The Widman Action does not include claims for inverse condemnation. The parties to the Blakeley Proceeding agreed to a preliminary mediation no later than 60 days prior to the liability trial, and, if there is a trial following that mediation and if the jury returns a verdict in the plaintiffs' favor in the liability trial, a second mediation within 90 days following the verdict focusing on damages. Finally, the plaintiffs agreed to complete a damages questionnaire identifying all claimed damages being sought in connection with the litigation.
In June 2024, a motion was filed in one of the individual actions (the "VanDyke Action") to add three additional plaintiffs. Although the statute of limitations for new claims has passed, the plaintiffs argued that the addition of new plaintiffs is timely because the lawsuit was initially pled as a class action. The Court subsequently allowed two of the proposed plaintiffs to be added to the action on the grounds that they were minors at the time of the incident, but denied the remainder of the motion.
The Company will vigorously defend itself in the legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Orofino Fire
In August 2023, a fire subsequently referred to as the "Hospital Fire" started in windy conditions near Orofino, Idaho, burning
Colstrip
Colstrip Owners Arbitration and Litigation
Colstrip Units 3 and 4 are owned by the Company, PacifiCorp, Portland General Electric (PGE), and Puget Sound Energy (PSE) (collectively, the "Western Co-Owners"), as well as NorthWestern and Talen Montana, LLC (Talen), as tenants in common under an Ownership and Operating Agreement, dated May 6, 1981, as amended (O&O Agreement), in the percentages set forth below:
Co-Owner |
|
Unit 3 |
|
|
Unit 4 |
|
||
Avista |
|
|
% |
|
|
% |
||
PacifiCorp |
|
|
% |
|
|
% |
||
PGE |
|
|
% |
|
|
% |
||
PSE |
|
|
% |
|
|
% |
||
NorthWestern |
|
|
— |
|
|
|
% |
|
Talen |
|
|
% |
|
|
— |
|
36
Colstrip Units 1 and 2, owned by PSE and Talen, were shut down in 2020 and are in the process of being decommissioned. The co-owners of Units 3 and 4 also own undivided interests in facilities common to both Units 3 and 4, as well as in certain facilities common to all four Colstrip units.
The Washington Clean Energy Transformation Act (CETA), among other things, imposes deadlines by which each electric utility must eliminate from its electricity rates in Washington the costs and benefits associated with coal-fired resources, such as Colstrip. The practical impact of CETA is electricity from such resources, including Colstrip, may no longer be delivered to Washington retail customers after 2025.
The co-owners of Colstrip Units 3 and 4 have differing needs for the generating capacity of these units. Accordingly, certain business disagreements have arisen among the co-owners, including, disagreements as to the requirements for shutting down these units.
Agreement Between Avista and NorthWestern
In January 2023, the Company entered into an agreement with NorthWestern under which, subject to the terms and conditions specified in the agreement, the Company will transfer its
Under the agreement, the Company will remain obligated through the close of the transaction to pay its share of (i) operating expenses, (ii) capital expenditures, but not in excess of the portion allocable pro rata to the portion of useful life (through 2030) expired through the close of the transaction, and (iii) site remediation expenses except certain costs relating to post closing activities. In addition, the Company would enter into an agreement under which it would retain its voting rights with respect to decisions relating to remediation.
The Company will retain its Colstrip transmission system assets, which are excluded from the transaction.
The transaction is subject to the satisfaction of customary closing conditions including NorthWestern's ability to enter into a new coal supply agreement by December 31, 2024.
The Company does not expect this transaction to have a direct material impact on its financial results.
Agreement Between PSE and NorthWestern
In July 2024, PSE entered into an agreement with NorthWestern under which, PSE will transfer its
Burnett et al. v. Talen et al.
Multiple property owners initiated a legal proceeding (titled Burnett et al. v. Talen et al.) in the Montana District Court for Rosebud County against Talen, PSE, PacifiCorp, PGE, Avista Corp., NorthWestern, and Westmoreland Rosebud Mining. The plaintiffs allege a failure to contain coal dust in connection with the operation of Colstrip, and seek unspecified damages. The Colstrip owners reached a settlement with one of the litigants, Richard Burnett, for an amount of less than $
37
Westmoreland Mine Permits
Two lawsuits have been commenced by the Montana Environmental Information Center and others, challenging certain permits relating to the operation of the Westmoreland Rosebud Mine, which provides coal to Colstrip. In the first, the Montana District Court for Rosebud County issued an order vacating a permit for one area of the mine, which decision was subsequently upheld by the Montana Supreme Court. In the second, the Montana Federal District Court vacated a decision by the federal Office of Surface Mining Reclamation and Enforcement, a branch of the United States Department of the Interior, approving expansion of the mine into a new area, pending further analysis of potential environmental impact. An initial appeal of that decision to the Ninth Circuit was dismissed for lack of jurisdiction, pending further proceedings before the Department of the Interior. Avista Corp. is not a party to either of these proceedings, but continues to monitor the progress of both issues and assess the impact, if any, of the proceedings on Westmoreland’s ability to meet its contractual coal supply obligations.
National Park Service (NPS) - Natural and Cultural Damage Claim
In March 2017, the Company accessed property managed by the National Park Service (NPS) to prevent the imminent failure of a power pole surrounded by flood water in the Spokane River. The Company voluntarily reported its actions to the NPS several days later. Thereafter, in March 2018, the NPS notified the Company that it might seek recovery for unspecified costs and damages allegedly caused during the incident pursuant to the System Unit Resource Protection Act (SURPA), 54 U.S.C. 100721 et seq. In January 2021, the United States Department of Justice (DOJ) requested the Company and the DOJ renew discussions relating to the matter. In July 2021, the DOJ communicated that it may seek damages of approximately $
In April 2024 the parties reached a settlement in principle, through which the Company has agreed to pay $
Rathdrum, Idaho Natural Gas Incident
In October 2021, there was an incident in Rathdrum, Idaho involving the Company’s natural gas infrastructure. The incident occurred after a third party damaged those facilities during excavation work. The incident resulted in a fire which destroyed one residence and resulted in minor injuries to the occupants. In January 2023, the Company was served with a lawsuit filed in the District Court of Kootenai County, Idaho by one property owner, seeking unspecified damages. In February 2024, the Company received a second lawsuit filed by the owners of the adjacent property, seeking damages for personal injury and emotional distress from having witnessed the incident. The Company will vigorously defend itself in the legal proceedings; however, at this time the Company is unable to predict the likelihood of an adverse outcome or estimate a range of potential loss in the event of such an outcome.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes any liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. See "Note 22 of the Notes to Consolidated Financial Statements" in the 2023 Form 10-K for additional discussion regarding other contingencies.
NOTE 16. INFORMATION BY BUSINESS SEGMENTS
The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss). The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered
38
the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with other operating segments. The Other category, which is not a reportable segment, includes other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital.
The following table presents information for each of the Company’s business segments (dollars in thousands):
|
|
Avista |
|
|
Alaska |
|
|
Total Utility |
|
|
Other |
|
|
Intersegment |
|
|
Total |
|
||||||
For the three months ended September 30, 2024: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Resource costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Other operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Income (loss) from operations |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Interest expense (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||||
Income tax benefit |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Capital expenditures (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
For the three months ended September 30, 2023: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Resource costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Other operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Income (loss) from operations |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Interest expense (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||||
Income tax expense (benefit) |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|
|
( |
) |
|||
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Capital expenditures (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
For the nine months ended September 30, 2024: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Resource costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Other operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Income (loss) from operations |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Interest expense (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||||
Income tax expense (benefit) |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Capital expenditures (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
For the nine months ended September 30, 2023: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Operating revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||||
Resource costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Other operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Income (loss) from operations |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Interest expense (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||||
Income tax expense (benefit) |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
|
|
|
|
( |
) |
||
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|||||
Capital expenditures (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
As of September 30, 2024: |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||||
As of December 31, 2023: |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
39
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
Avista Corporation
Results of Review of Interim Financial Information
We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the "Company") as of September 30, 2024, the related condensed consolidated statements of income, comprehensive income, and equity for the three-month and nine-month periods ended September 30, 2024 and 2023, and of cash flows for the nine-month periods ended September 30, 2024 and 2023 and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2023, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 20, 2024, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2023, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Portland, Oregon
November 5, 2024
40
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, |
|
|
Nine months ended September 30, |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
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).
41
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.
42
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:
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:
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.
43
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
44
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.
45
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.
46
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.
47
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 |
|
|
Natural Gas Customers |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
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):
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.
49
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 |
|
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:
50
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):
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.
51
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 |
|
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:
52
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:
53
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:
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 |
|
|
Natural Gas |
|
|
Intracompany |
|
|
Total |
|
||||||||||||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
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.
54
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 |
|
|
Natural Gas Customers |
|
||||||||||
|
|
2024 |
|
|
2023 |
|
|
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):
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.
55
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 |
|
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:
56
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):
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.
57
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 |
) |
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:
58
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:
59
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:
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 |
|
|
Natural Gas |
|
|
Intracompany |
|
|
Total |
|
||||||||||||||||||||
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
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.
60
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
61
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 |
|
|
December 31, 2023 |
|
||||||||||
|
|
Amount |
|
|
Percent |
|
|
Amount |
|
|
Percent |
|
||||
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
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):
|
|
2024 |
|
|
2023 |
|
||
$500 million line of credit, expiring June 2028 |
|
|
|
|
|
|
||
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.
63
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.
64
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:
65
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.
66
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.
|
|
Purchases |
|
|
Sales |
|
||||||||||||||||||||||||||
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
||||||||||||||||||||
Year |
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
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.
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|
Purchases |
|
|
Sales |
|
||||||||||||||||||||||||||
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
|
Electric Derivatives |
|
|
Gas Derivatives |
|
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Year |
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
Physical (1) |
|
|
Financial (1) |
|
|
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 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
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.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
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.
Item 4. Controls and Procedures
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
67
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.
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PART II. Other Information
Item 1. Legal Proceedings
See “Note 15 of Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”
Item 1A. Risk Factors
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.
Item 5. Other Information
During the fiscal quarter ended September 30, 2024, none of our directors or officers informed us of the
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Item 6. Exhibits
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101.INS |
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Inline XBRL Instance Document. The instance document does not appear in the interactive data file because its inline XBRL tags are embedded within the inline XBRL document. |
101.SCH |
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Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents |
104 |
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Cover page formatted as Inline XBRL and contained in Exhibit 101. |
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(1) |
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Filed herewith. |
(2) |
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Furnished herewith. |
70
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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AVISTA CORPORATION |
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(Registrant) |
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Date: |
November 5, 2024 |
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/s/ Kevin J. Christie |
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Kevin J. Christie |
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Senior Vice President, Chief Financial Officer, Treasurer and Regulatory Affairs Officer (Principal Financial Officer) |
71