PINNACLE WEST CAPITAL CORP
10-Qs and 10-Ks
PROXIES
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
10-Q
(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the quarterly period ended
March 31, 2025
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from to
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Commission File
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Exact name of each registrant as specified in its
charter; State or other jurisdiction of incorporation or organization; Address of principal executive offices, including zip code; and Telephone number, including area code |
IRS Employer
Identification No. |
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Securities registered pursuant to Section 12(b) of the Act:
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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 each 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.
| PINNACLE WEST CAPITAL CORPORATION |
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☒
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No |
☐
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| ARIZONA PUBLIC SERVICE COMPANY |
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No |
☐
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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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
| PINNACLE WEST CAPITAL CORPORATION |
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☒ | No | ☐ | |||||||||||||
| ARIZONA PUBLIC SERVICE COMPANY |
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☒ | No | ☐ | |||||||||||||
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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.
PINNACLE WEST CAPITAL CORPORATION
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Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company |
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| Emerging growth company |
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ARIZONA PUBLIC SERVICE COMPANY
| Large accelerated filer | ☐ | Accelerated filer | ☐ |
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☒
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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 each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| PINNACLE WEST CAPITAL CORPORATION | Yes | ☐ | No |
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| ARIZONA PUBLIC SERVICE COMPANY | Yes | ☐ | No |
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Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
| PINNACLE WEST CAPITAL CORPORATION | Number of shares of common stock, no par value, outstanding as of April 24, 2025: |
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| ARIZONA PUBLIC SERVICE COMPANY | Number of shares of common stock, $2.50 par value, outstanding as of April 24, 2025: |
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Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.
TABLE OF CONTENTS
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This combined quarterly report on Form 10-Q is separately provided by Pinnacle West Capital Corporation (“Pinnacle West”) and Arizona Public Service Company (“APS”). Any use of the words “Company,” “we,” and “our” refer to Pinnacle West unless context otherwise requires. Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information. The information required with respect to each company is set forth within the applicable items. Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS. Item 1 of this report also includes Combined Notes to Condensed Consolidated Financial Statements.
FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” “anticipate,” “goal,” “seek,” “strategy,” “likely,” “should,” “will,” “could,” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended
December 31, 2024
(“
2024
Form 10-K”), and Part II, Item 1A of this report, these factors include, but are not limited to:
•
uncertainties associated with the current and future economic environment, including economic growth rates, labor market conditions, inflation, supply chain delays, increased expenses, volatile capital markets, or other unpredictable effects;
•
current and future economic conditions in Arizona, such as the housing market and overall business and regulatory environment;
•
our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;
•
the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, or other catastrophic events, such as fires, explosions, pandemic health events, or similar occurrences;
•
variations in demand for electricity, including those due to weather, seasonality (including large increases in ambient temperatures), the general economy or social conditions, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;
•
the potential effects of climate change on our electric system, including as a result of weather extremes, such as prolonged drought and high temperature variations in the area where APS conducts its business;
•
power plant and transmission system performance and outages;
•
competition in retail and wholesale power markets;
•
regulatory and judicial decisions, developments, and proceedings;
•
new legislation, ballot initiatives, and regulation or interpretations of existing legislation or regulations, including those relating to environmental requirements, regulatory and energy policy, nuclear plant operations, and potential deregulation of retail electric markets;
•
fuel and water supply availability;
•
our ability to achieve timely and adequate rate recovery of our costs through our rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investment;
•
the ability of APS to meet renewable energy and energy efficiency mandates and recover related costs;
•
the ability of APS to achieve its clean energy goals (including a goal by 2050 of 100% clean, carbon-free electricity) and, if these goals are achieved, the impact of such achievement on APS, its customers, and its business, financial condition, and results of operations;
•
risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;
•
the development of new technologies which may affect electric sales or delivery, including as a result of delays in the development and application of new technologies;
•
the cost of debt, including increased cost as a result of rising interest rates, and equity capital and our ability to access capital markets when required;
•
environmental, economic, and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions (“GHG”);
•
volatile fuel and purchased power costs;
•
the investment performance of the assets of our nuclear decommissioning trust, captive insurance cell, coal mine reclamation escrow, pension, and other postretirement benefit plans, and the resulting impact on future funding requirements;
•
the liquidity of wholesale power markets and the use of derivative contracts in our business;
1
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potential shortfalls in insurance coverage;
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new accounting requirements or new interpretations of existing requirements;
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generation, transmission, and distribution facilities and system conditions and operating costs;
•
our ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;
•
the willingness or ability of counterparties, power plant participants, and power plant landowners to meet contractual or other obligations or extend the rights for continued power plant operations; and
•
restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission (“ACC”) orders.
These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our
2024
Form 10-K, Part II, Item 1A of this report, and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.
2
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
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3
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
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OPERATING REVENUES (Note 4)
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$ |
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$ |
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| OPERATING EXPENSES | ||||||||||||||
| Fuel and purchased power |
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| Operations and maintenance |
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| Depreciation and amortization |
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| Taxes other than income taxes |
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| Other expense |
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| Total |
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OPERATING INCOME
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| OTHER INCOME (DEDUCTIONS) | ||||||||||||||
| Allowance for equity funds used during construction |
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Pension and other postretirement non-service credits - net (Note 7)
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Other income (Note 11)
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Other expense (Note 11)
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(
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(
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| Total |
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| INTEREST EXPENSE | ||||||||||||||
| Interest charges |
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| Allowance for borrowed funds used during construction |
(
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(
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| Total |
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Income (Loss) Before Income Taxes
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(
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Income taxes (benefit)
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(
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Net Income (Loss)
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(
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Less: Net income attributable to noncontrolling interests (Note 8)
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Net Income (Loss) Attributable to Common Shareholders
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$ |
(
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$ |
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| Weighted-average common shares outstanding - basic |
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| Weighted-average common shares outstanding - diluted |
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| Earnings Per Weighted-Average Common Share Outstanding | ||||||||||||||
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Net income (loss) attributable to common shareholders - basic
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$ |
(
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$ |
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Net income (loss) attributable to common shareholders - diluted
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$ |
(
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$ |
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The accompanying notes are an integral part of the financial statements.
4
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
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NET INCOME (LOSS)
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$ |
(
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$ |
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OTHER COMPREHENSIVE INCOME, NET OF TAX
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| Derivative instruments: | |||||||||||
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Net unrealized gain (loss), net of tax benefit (expense) of $
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Pension and other postretirement benefit activity, net of tax expense of $(
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Total other comprehensive income
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COMPREHENSIVE INCOME
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Less: Comprehensive income attributable to noncontrolling interests
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COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS
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$ |
(
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$ |
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The accompanying notes are an integral part of the financial statements.
5
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
March 31,
2025 |
December 31,
2024 |
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| ASSETS | |||||||||||
| CURRENT ASSETS | |||||||||||
| Cash and cash equivalents | $ |
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$ |
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| Customer and other receivables |
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Accrued unbilled revenues (Note 4)
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Allowance for doubtful accounts (Note 4)
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(
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(
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| Materials and supplies (at average cost) |
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| Fossil fuel (at average cost) |
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Assets from risk management activities (Note 9)
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Deferred fuel and purchased power regulatory asset (Note 6)
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Other regulatory assets (Note 6)
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| Other current assets |
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| Total current assets |
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| INVESTMENTS AND OTHER ASSETS | |||||||||||
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Nuclear decommissioning trusts (Notes 13 and 14)
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Other special use funds (Notes 13 and 14)
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Assets from risk management activities (Note 9)
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| Other assets |
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| Total investments and other assets |
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| PROPERTY, PLANT AND EQUIPMENT | |||||||||||
| Plant in service and held for future use |
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| Accumulated depreciation and amortization |
(
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(
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| Net |
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| Construction work in progress |
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Palo Verde sale leaseback, net of accumulated depreciation (Note 8)
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| Intangible assets, net of accumulated amortization |
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| Nuclear fuel, net of accumulated amortization |
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| Total property, plant and equipment |
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| DEFERRED DEBITS | |||||||||||
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Regulatory assets (Note 6)
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Operating lease right-of-use assets (Note 16)
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Assets for pension and other postretirement benefits (Note 7)
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| Other |
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| Total deferred debits |
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| TOTAL ASSETS | $ |
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$ |
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The accompanying notes are an integral part of the financial statements.
6
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
March 31,
2025 |
December 31,
2024 |
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| LIABILITIES AND EQUITY | |||||||||||
| CURRENT LIABILITIES | |||||||||||
| Accounts payable | $ |
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$ |
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| Accrued taxes |
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| Accrued interest |
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| Common dividends payable |
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Short-term borrowings (Note 5)
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Current maturities of long-term debt (Note 5)
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| Customer deposits |
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Liabilities from risk management activities (Note 9)
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Liabilities for asset retirements
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Operating lease liabilities (Note 16)
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Regulatory liabilities (Note 6)
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| Other current liabilities |
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| Total current liabilities |
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LONG-TERM DEBT LESS CURRENT MATURITIES (Note 5)
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| DEFERRED CREDITS AND OTHER | |||||||||||
| Deferred income taxes |
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Regulatory liabilities (Note 6)
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Liabilities for asset retirements
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Liabilities for pension benefits (Note 7)
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Liabilities from risk management activities (Note 9)
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| Customer advances |
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| Coal mine reclamation |
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| Deferred investment tax credit |
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| Unrecognized tax benefits |
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Operating lease liabilities (Note 16)
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| Other |
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| Total deferred credits and other |
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COMMITMENTS AND CONTINGENCIES (Note 10)
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| EQUITY | |||||||||||
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Common stock, no par value; authorized
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Treasury stock at cost;
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(
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(
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| Total common stock |
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| Retained earnings |
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Accumulated other comprehensive loss (Note 15)
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(
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(
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| Total shareholders’ equity |
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Noncontrolling interests (Note 8)
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| Total equity |
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| TOTAL LIABILITIES AND EQUITY | $ |
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$ |
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The accompanying notes are an integral part of the financial statements.
7
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
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Net income (loss)
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$ |
(
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$ |
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| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Gain on sale relating to BCE |
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(
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| Depreciation and amortization including nuclear fuel |
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| Deferred fuel and purchased power |
(
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(
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| Deferred fuel and purchased power amortization |
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| Allowance for equity funds used during construction |
(
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(
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| Deferred income taxes |
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(
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| Deferred investment tax credit |
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(
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| Stock compensation |
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| Changes in current assets and liabilities: | |||||||||||
| Customer and other receivables |
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| Accrued unbilled revenues |
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| Materials, supplies and fossil fuel |
(
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| Income tax receivable |
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| Other current assets |
(
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(
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| Accounts payable |
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| Accrued taxes |
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| Other current liabilities |
(
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(
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| Change in long-term regulatory assets |
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| Change in long-term regulatory liabilities |
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| Change in other long-term assets |
(
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(
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| Change in operating lease assets |
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(
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| Change in other long-term liabilities |
(
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(
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| Change in operating lease liabilities |
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| Net cash provided by operating activities |
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| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
| Capital expenditures |
(
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(
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| Contributions in aid of construction |
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| Proceeds from sale relating to BCE |
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| Allowance for borrowed funds used during construction |
(
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(
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| Proceeds from nuclear decommissioning trusts sales and other special use funds |
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| Investment in nuclear decommissioning trusts and other special use funds |
(
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(
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| Other |
(
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(
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| Net cash used for investing activities |
(
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(
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| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
| Short-term borrowing and (repayments) - net |
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| Dividends paid on common stock |
(
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(
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| Common stock equity issuance and (purchases) - net |
(
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(
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| Other |
(
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| Net cash provided by financing activities |
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NET INCREASE IN CASH AND CASH EQUIVALENTS
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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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The accompanying notes are an integral part of the financial statements.
8
PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||
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Balance, December 31, 2024
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$ |
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(
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$ |
(
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$ |
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$ |
(
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$ |
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$ |
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Net income (loss)
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— | — |
(
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— |
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(
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Other comprehensive income
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— | — | — |
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— |
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| Issuance of common stock (a) |
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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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Balance, March 31, 2025
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$ |
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(
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$ |
(
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$ |
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$ |
(
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$ |
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$ |
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|||||||||||||||||||||||||||||||||
| Three Months Ended March 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||
|
Balance, December 31, 2023
|
|
$ |
|
(
|
$ |
(
|
$ |
|
$ |
(
|
$ |
|
$ |
|
|||||||||||||||||||||||||||||||||
|
Net income
|
— | — |
|
— |
|
|
|||||||||||||||||||||||||||||||||||||||||
|
Other comprehensive income
|
— | — | — |
|
— |
|
|||||||||||||||||||||||||||||||||||||||||
| Issuance of common stock (a) |
|
|
— | — | — | — |
|
||||||||||||||||||||||||||||||||||||||||
| Purchase of treasury stock (b) | — |
(
|
(
|
— | — | — |
(
|
||||||||||||||||||||||||||||||||||||||||
| Reissuance of treasury stock for stock-based compensation and other | — |
|
|
— | — | — |
|
||||||||||||||||||||||||||||||||||||||||
| Other | — |
|
(
|
— | — |
|
|||||||||||||||||||||||||||||||||||||||||
|
Balance, March 31, 2024
|
|
$ |
|
(
|
$ |
(
|
$ |
|
$ |
(
|
$ |
|
$ |
|
|||||||||||||||||||||||||||||||||
(a)
See Note 12 for information related to our equity forward sale agreements.
(b)
Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
The accompanying notes are an integral part of the financial statements.
9
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
|
OPERATING REVENUES (Note 4)
|
$ |
|
$ |
|
||||||||||
| OPERATING EXPENSES | ||||||||||||||
| Fuel and purchased power |
|
|
||||||||||||
| Operations and maintenance |
|
|
||||||||||||
| Depreciation and amortization |
|
|
||||||||||||
| Taxes other than income taxes |
|
|
||||||||||||
| Other expense |
|
|
||||||||||||
| Total |
|
|
||||||||||||
|
OPERATING INCOME
|
|
|
||||||||||||
| OTHER INCOME (DEDUCTIONS) | ||||||||||||||
| Allowance for equity funds used during construction |
|
|
||||||||||||
|
Pension and other postretirement non-service credits - net (Note 7)
|
|
|
||||||||||||
|
Other income (Note 11)
|
|
|
||||||||||||
|
Other expense (Note 11)
|
(
|
(
|
||||||||||||
| Total |
|
|
||||||||||||
| INTEREST EXPENSE | ||||||||||||||
| Interest charges |
|
|
||||||||||||
| Allowance for borrowed funds used during construction |
(
|
(
|
||||||||||||
| Total |
|
|
||||||||||||
|
Income Before Income Taxes
|
|
|
||||||||||||
|
Income taxes (benefit)
|
(
|
|
||||||||||||
|
Net Income
|
|
|
||||||||||||
|
Less: Net income attributable to noncontrolling interests (Note 8)
|
|
|
||||||||||||
|
Net Income Attributable to Common Shareholder
|
$ |
|
$ |
|
||||||||||
The accompanying notes are an integral part of the financial statements.
10
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
|
NET INCOME
|
$ |
|
$ |
|
|||||||
|
OTHER COMPREHENSIVE INCOME, NET OF TAX
|
|||||||||||
|
Pension and other postretirement benefits activity, net of tax expense of $(
|
|
|
|||||||||
|
Total other comprehensive income
|
|
|
|||||||||
|
COMPREHENSIVE INCOME
|
|
|
|||||||||
|
Less: Comprehensive income attributable to noncontrolling interests
|
|
|
|||||||||
|
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
|
$ |
|
$ |
|
|||||||
The accompanying notes are an integral part of the financial statements.
11
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
March 31,
2025 |
December 31,
2024 |
||||||||||
| ASSETS | |||||||||||
| PROPERTY, PLANT AND EQUIPMENT | |||||||||||
| Plant in service and held for future use | $ |
|
$ |
|
|||||||
| Accumulated depreciation and amortization |
(
|
(
|
|||||||||
| Net |
|
|
|||||||||
| Construction work in progress |
|
|
|||||||||
|
Palo Verde sale leaseback, net of accumulated depreciation (Note 8)
|
|
|
|||||||||
| Intangible assets, net of accumulated amortization |
|
|
|||||||||
| Nuclear fuel, net of accumulated amortization |
|
|
|||||||||
| Total property, plant and equipment |
|
|
|||||||||
| INVESTMENTS AND OTHER ASSETS | |||||||||||
|
Nuclear decommissioning trusts (Notes 13 and 14)
|
|
|
|||||||||
|
Other special use funds (Notes 13 and 14)
|
|
|
|||||||||
|
Assets from risk management activities (Note 9)
|
|
|
|||||||||
| Other assets |
|
|
|||||||||
| Total investments and other assets |
|
|
|||||||||
| CURRENT ASSETS | |||||||||||
| Cash and cash equivalents |
|
|
|||||||||
| Customer and other receivables |
|
|
|||||||||
|
Accrued unbilled revenues (Note 4)
|
|
|
|||||||||
|
Allowance for doubtful accounts (Note 4)
|
(
|
(
|
|||||||||
| Materials and supplies (at average cost) |
|
|
|||||||||
| Fossil fuel (at average cost) |
|
|
|||||||||
| Income tax receivable |
|
|
|||||||||
|
Assets from risk management activities (Note 9)
|
|
|
|||||||||
|
Deferred fuel and purchased power regulatory asset (Note 6)
|
|
|
|||||||||
|
Other regulatory assets (Note 6)
|
|
|
|||||||||
| Other current assets |
|
|
|||||||||
| Total current assets |
|
|
|||||||||
| DEFERRED DEBITS | |||||||||||
|
Regulatory assets (Note 6)
|
|
|
|||||||||
|
Operating lease right-of-use assets (Note 16)
|
|
|
|||||||||
|
Assets for pension and other postretirement benefits (Note 7)
|
|
|
|||||||||
| Other |
|
|
|||||||||
| Total deferred debits |
|
|
|||||||||
| TOTAL ASSETS | $ |
|
$ |
|
|||||||
The accompanying notes are an integral part of the financial statements.
12
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
|
March 31,
2025 |
December 31,
2024 |
||||||||||
| LIABILITIES AND EQUITY | |||||||||||
| CAPITALIZATION | |||||||||||
| Common stock | $ |
|
$ |
|
|||||||
| Additional paid-in capital |
|
|
|||||||||
| Retained earnings |
|
|
|||||||||
|
Accumulated other comprehensive loss (Note 15)
|
(
|
(
|
|||||||||
| Total shareholder equity |
|
|
|||||||||
|
Noncontrolling interests (Note 8)
|
|
|
|||||||||
| Total equity |
|
|
|||||||||
|
Long-term debt less current maturities (Note 5)
|
|
|
|||||||||
| Total capitalization |
|
|
|||||||||
| CURRENT LIABILITIES | |||||||||||
|
Short-term borrowings (Note 5)
|
|
|
|||||||||
|
Current maturities of long-term debt (Note 5)
|
|
|
|||||||||
| Accounts payable |
|
|
|||||||||
| Accrued taxes |
|
|
|||||||||
| Accrued interest |
|
|
|||||||||
| Common dividends payable |
|
|
|||||||||
| Customer deposits |
|
|
|||||||||
|
Liabilities from risk management activities (Note 9)
|
|
|
|||||||||
|
Liabilities for asset retirements
|
|
|
|||||||||
|
Operating lease liabilities (Note 16)
|
|
|
|||||||||
|
Regulatory liabilities (Note 6)
|
|
|
|||||||||
| Other current liabilities |
|
|
|||||||||
| Total current liabilities |
|
|
|||||||||
| DEFERRED CREDITS AND OTHER | |||||||||||
| Deferred income taxes |
|
|
|||||||||
|
Regulatory liabilities (Note 6)
|
|
|
|||||||||
|
Liabilities for asset retirements
|
|
|
|||||||||
|
Liabilities for pension benefits (Note 7)
|
|
|
|||||||||
|
Liabilities from risk management activities (Note 9)
|
|
|
|||||||||
| Customer advances |
|
|
|||||||||
| Coal mine reclamation |
|
|
|||||||||
| Deferred investment tax credit |
|
|
|||||||||
| Unrecognized tax benefits |
|
|
|||||||||
|
Operating lease liabilities (Note 16)
|
|
|
|||||||||
| Other |
|
|
|||||||||
| Total deferred credits and other |
|
|
|||||||||
|
COMMITMENTS AND CONTINGENCIES (Note 10)
|
|
|
|||||||||
| TOTAL LIABILITIES AND EQUITY | $ |
|
$ |
|
|||||||
The accompanying notes are an integral part of the financial statements.
13
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
|
Net income
|
$ |
|
$ |
|
|||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization including nuclear fuel |
|
|
|||||||||
| Deferred fuel and purchased power |
(
|
(
|
|||||||||
| Deferred fuel and purchased power amortization |
|
|
|||||||||
| Allowance for equity funds used during construction |
(
|
(
|
|||||||||
| Deferred income taxes |
(
|
|
|||||||||
| Deferred investment tax credit |
|
(
|
|||||||||
| Changes in current assets and liabilities: | |||||||||||
| Customer and other receivables |
|
|
|||||||||
| Accrued unbilled revenues |
|
|
|||||||||
| Materials, supplies and fossil fuel |
(
|
|
|||||||||
| Income tax receivable |
|
|
|||||||||
| Other current assets |
(
|
|
|||||||||
| Accounts payable |
|
|
|||||||||
| Accrued taxes |
|
|
|||||||||
| Other current liabilities |
(
|
(
|
|||||||||
| Change in long-term regulatory assets |
|
|
|||||||||
| Change in long-term regulatory liabilities |
|
|
|||||||||
| Change in other long-term assets |
(
|
(
|
|||||||||
| Change in operating lease assets |
|
(
|
|||||||||
| Change in other long-term liabilities |
(
|
(
|
|||||||||
| Change in operating lease liabilities |
|
|
|||||||||
| Net cash provided by operating activities |
|
|
|||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
| Capital expenditures |
(
|
(
|
|||||||||
| Contributions in aid of construction |
|
|
|||||||||
| Allowance for borrowed funds used during construction |
(
|
(
|
|||||||||
| Proceeds from nuclear decommissioning trusts sales and other special use funds |
|
|
|||||||||
| Investment in nuclear decommissioning trusts and other special use funds |
(
|
(
|
|||||||||
| Other |
(
|
(
|
|||||||||
| Net cash used for investing activities |
(
|
(
|
|||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
| Short-term borrowing and (repayments) - net |
|
|
|||||||||
| Dividends paid on common stock |
(
|
(
|
|||||||||
| Net cash provided by financing activities |
|
|
|||||||||
|
NET INCREASE IN CASH AND CASH EQUIVALENTS
|
|
|
|||||||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
|
|
|||||||||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ |
|
$ |
|
|||||||
The accompanying notes are an integral part of the financial statements.
14
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(unaudited)
(dollars in thousands)
| Three Months Ended March 31, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||||||||||||||
|
Balance, December 31, 2024
|
|
$ |
|
$ |
|
$ |
|
$ |
(
|
$ |
|
$ |
|
||||||||||||||||||||||||||||
|
Net income
|
— | — |
|
— |
|
|
|||||||||||||||||||||||||||||||||||
|
Other comprehensive income
|
— | — | — |
|
— |
|
|||||||||||||||||||||||||||||||||||
| Other | — | — |
(
|
— |
|
(
|
|||||||||||||||||||||||||||||||||||
|
Balance, March 31, 2025
|
|
$ |
|
$ |
|
$ |
|
$ |
(
|
$ |
|
$ |
|
||||||||||||||||||||||||||||
| Three Months Ended March 31, 2024 | |||||||||||||||||||||||||||||||||||||||||
| Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||||||||||||||
| Shares | Amount | ||||||||||||||||||||||||||||||||||||||||
|
Balance, December 31, 2023
|
|
$ |
|
$ |
|
$ |
|
$ |
(
|
$ |
|
$ |
|
||||||||||||||||||||||||||||
|
Net income
|
— | — |
|
— |
|
|
|||||||||||||||||||||||||||||||||||
|
Other comprehensive income
|
— | — | — |
|
— |
|
|||||||||||||||||||||||||||||||||||
| Other | — | — |
(
|
— | — |
(
|
|||||||||||||||||||||||||||||||||||
|
Balance, March 31, 2024
|
|
$ |
|
$ |
|
$ |
|
$ |
(
|
$ |
|
$ |
|
||||||||||||||||||||||||||||
The accompanying notes are an integral part of the financial statements.
15
1.
Consolidation and Nature of Operations
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado Investment Company (“El Dorado”), and Pinnacle West Power, LLC (“PNW Power”).
Intercompany accounts and transactions between the consolidated companies have been eliminated. The unaudited Condensed Consolidated Financial Statements for Pinnacle West include the accounts of Pinnacle West and its subsidiaries as well as a variable interest entity (“VIE”) related to a Captive Insurance Cell (“Captive”). The unaudited Condensed Consolidated Financial Statements for APS include the accounts of APS and the Palo Verde Generating Station (“Palo Verde”) VIEs.
See Note 8 for further discussion on Pinnacle West’s VIEs. El Dorado is a wholly-owned subsidiary that invests in energy-related and Arizona community-based ventures. PNW Power is a wholly-owned subsidiary that holds certain investments in wind and transmission joint venture projects that were previously held by Bright Canyon Energy Corporation (“BCE”).
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
BCE was a Pinnacle West subsidiary that was formed in 2014.
On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold.
The sale was completed on January 12, 2024.
See Note
18 for more information relating to the sale of BCE.
Amounts reported in our unaudited Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented.
Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.
The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2024 Form 10-K.
16
Supplemental Cash Flow Information
The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
|
Cash paid (received) during the period for:
|
|||||||||||
| Income taxes, net of refunds | $ |
(
|
$ |
|
|||||||
| Interest, net of amounts capitalized |
|
|
|||||||||
| Significant non-cash investing and financing activities: | |||||||||||
| Accrued capital expenditures | $ |
|
$ |
|
|||||||
|
BCE Sale non-cash consideration (Note 18)
|
|
|
|||||||||
The following table summarizes supplemental APS cash flow information (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
|
Cash paid (received) during the period for:
|
|||||||||||
| Income taxes, net of refunds | $ |
(
|
$ |
|
|||||||
| Interest, net of amounts capitalized |
|
|
|||||||||
| Significant non-cash investing and financing activities: | |||||||||||
| Accrued capital expenditures | $ |
|
$ |
|
|||||||
2.
Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.
For segment reporting purposes, Pinnacle West’s Chief Executive Officer performs the function of chief operating decision maker (“CODM”). Our CODM uses net income to measure an operating segment’s profitability. When assessing the performance of an operating segment, and making decisions about allocating resources, our CODM evaluates net income actual results compared to budget. Net income is also used when implementing strategic initiatives and selecting projects to meet business objectives. Our reportable segment’s revenue streams are dependent upon regulated rate recovery, which is a primary factor in how we identify operating segments.
17
| Three Months Ended March 31, | |||||||||||||||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||||||||||||||
| Regulated Electricity Segment | Other | Pinnacle West Consolidated | Regulated Electricity Segment | Other | Pinnacle West Consolidated | ||||||||||||||||||||||||||||||
| Operating Revenues | $ |
|
$ |
|
$ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||||||||||
| Fuel and purchased power |
(
|
|
(
|
(
|
|
(
|
|||||||||||||||||||||||||||||
| Operations and maintenance |
(
|
(
|
(
|
(
|
(
|
(
|
|||||||||||||||||||||||||||||
| Depreciation and amortization |
(
|
|
(
|
(
|
|
(
|
|||||||||||||||||||||||||||||
| Taxes other than income taxes |
(
|
|
(
|
(
|
|
(
|
|||||||||||||||||||||||||||||
| Pension and other postretirement non-service credits, net |
|
|
|
|
|
|
|||||||||||||||||||||||||||||
| Allowance for equity funds used during construction |
|
|
|
|
|
|
|||||||||||||||||||||||||||||
| Other income and expenses, net |
|
|
|
|
|
|
|||||||||||||||||||||||||||||
| Interest expense and costs |
(
|
(
|
(
|
(
|
(
|
(
|
|||||||||||||||||||||||||||||
| Income Taxes |
|
|
|
(
|
|
(
|
|||||||||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interests |
(
|
|
(
|
(
|
|
(
|
|||||||||||||||||||||||||||||
| Net Income (Loss) | $ |
|
$ |
(
|
$ |
(
|
$ |
|
$ |
|
$ |
|
|||||||||||||||||||||||
The following table reconciles our reportable segment's assets to the Pinnacle West Consolidated amount (dollars in millions):
| March 31, 2025 | December 31, 2024 | ||||||||||||||||||||||||||||||||||
| Regulated Electricity Segment | Other | Pinnacle West Consolidated | Regulated Electricity Segment | Other | Pinnacle West Consolidated | ||||||||||||||||||||||||||||||
| Total Assets | $ |
|
$ |
|
$ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||||||||||
3.
New Accounting Standards
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures
In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We will adopt this standard on December 31, 2025, using a prospective approach. The adoption of the new standard will result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.
ASU 2024-03, Income Statement: Expense Disaggregation Disclosures
In November 2024, a new accounting standard was issued that requires specific disclosures related to certain costs and expenses. Companies will be required to disclose the amounts of certain cost and expense categories, such as: purchases of inventory, employee compensation, depreciation, and
18
amortization, among other disclosures. The new disclosures may be provided in the notes to the financial statements, and will not require changes to the face of the Statements of Income. The standard becomes effective on December 31, 2027, using either a prospective or retrospective approach, with early adoption permitted. The adoption of the new standard will result in disclosure changes, but will not impact our accounting for such costs and expenses or our financial statement results.
4.
Revenue
Sources of Revenue
The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Retail Electric Service | |||||||||||
| Residential | $ |
|
$ |
|
|||||||
| Non-Residential |
|
|
|||||||||
| Wholesale Energy Sales |
|
|
|||||||||
| Transmission Services for Others |
|
|
|||||||||
| Other Sources |
|
|
|||||||||
| Total Operating Revenues | $ |
|
$ |
|
|||||||
Retail Electric Revenues
All of Pinnacle West’s retail electric revenues are generated by APS.
Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage.
Revenues related to the sale of electricity are generally recognized when service is rendered, or electricity is delivered to customers.
The billing of electricity sales to individual customers is based on the reading of their meters.
We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided.
Customers are generally required to pay for services within 21 days of when the services are billed.
See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.
Wholesale Energy Sales and Transmission Services for Others
Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by the U.S. Federal Energy Regulatory Commission (“FERC”).
In the electricity business, some contracts to purchase energy are settled by netting against other contracts to sell electricity. This is referred to as a book-out, and usually occurs in contracts that have the
19
same terms (product type, quantities, and delivery points) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.
Revenue Activities
Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the three months ended March 31, 2025 and 2024 were $
1,019
million and $
943
million, respectively.
We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2025 and 2024 our revenues that do not qualify as revenue from contracts with customers were $
13
million and $
9
million, respectively. This amount includes revenues related to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 6 for a discussion of our regulatory cost recovery mechanisms.
Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of customer and other receivables and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and allowance for doubtful accounts.
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Balance at beginning of period | $ |
|
$ |
|
||||||||||
| Bad debt expense |
|
|
||||||||||||
| Actual write-offs |
(
|
(
|
||||||||||||
| Balance at end of period | $ |
|
$ |
|
||||||||||
5.
Debt and Liquidity Matters
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
20
Pinnacle West
As of March 31, 2025, Pinnacle West had a $
200
million revolving credit facility that matures on April 10, 2029. Pinnacle West has the option to increase the amount of the facility up to a total of $
300
million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $
200
million commercial paper program, for bank borrowings or for issuances of letters of credit. As of March 31, 2025, Pinnacle West had
no
outstanding borrowings under its revolving credit facility,
no
letters of credit outstanding under its credit facility, and $
44
million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2025 was
4.65
%.
Pinnacle West also has an outstanding
364
-day $
200
million term loan facility that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus
0.95
% per annum.
On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash. Pinnacle West also has an at-the-market equity distribution program (the “ATM Program”) under which it may offer and sell common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors. See Note 12 for more information on the February 2024 Forward Sale Agreements and the ATM Program.
APS
As of March 31, 2025, APS had a $
1.25
billion revolving credit facility, that matures on April 10, 2029. APS has the option to increase the amount of the facility by up to a maximum of
$
400
million
, for a total of $
1.65
billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which provides for an interest rate reduction or increase, by meeting or missing, respectively, targets related to specific environmental and employee health and safety sustainability objectives. Under certain circumstances, the sustainability-linked pricing metric can be terminated for the final year of the credit facility. The facility is available to support APS’s general corporate purposes, including support for APS’s $
1
billion commercial paper program
, for bank borrowings or for issuances of letters of credit.
As of March 31, 2025, APS had
no
outstanding borrowings under its revolving credit facility,
no
letters of credit outstanding under the credit facility, and $
627
million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on March 31, 2025 was
4.64
%.
On December 5, 2024, APS entered into a $
400
million
364
-Day Term Loan Agreement that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus
0.90
% per annum. On April 29, 2025, APS drew the full amount of $
400
million.
21
The ACC has authorized a limit on yearly equity infusions into APS equal to
2.5
% of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus
50
basis points.
See “Financial Assurances” in Note 10 for a discussion of other outst
anding letters of credit.
Debt Fair Value
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy.
The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
| As of March 31, 2025 | As of December 31, 2024 | ||||||||||||||||||||||
|
Carrying
Amount |
Fair Value |
Carrying
Amount |
Fair Value | ||||||||||||||||||||
| Pinnacle West | $ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||
| APS |
|
|
|
|
|||||||||||||||||||
| Total | $ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||
6.
Regulatory Matters
ACC General Retail Rate Cases
APS expects to file an application with the ACC for its next general rate case mid-year 2025 and is continuing to evaluate the timing of such filing.
2022 Retail Rate Case
APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates.
On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”) in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”). The 2022 Rate Case ROO recommended, among other things, (i) a $
523.1
million increase in the annual base rate revenue requirement, (ii) a
9.55
% return on equity, (iii) a
0.25
% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of
4.36
%, (v) 12 months of post-test year plant and the inclusion of the Four Corners Power Plant (“Four Corners”) Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a
5.0
% return on the prepaid pension asset and a return of
5.35
% on the Other Post-Employment Benefits liability, and (ix) no disallowances on APS’s coal contracts.
The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified Demand Side Management (“DSM”) performance incentives and the requested DSM transfer to base rates, (ii) the retention of $
1.9
million of Renewable Energy Adjustment Charge (“REAC”) in the adjustor rather than base rates, (iii) a partial transfer of $
27.1
million of Lost Fixed Cost
22
Recovery Mechanism (“LFCR”) funds to base rates, and (iv) the adoption of an increase in the annual Power Supply Adjustor (“PSA”) cap to $
0.006
/kWh.
On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $
491.7
million increase in the annual base revenue requirement, (ii) a
9.55
% return on equity, (iii) a
0.25
% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of
4.39
%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source request for proposal (“ASRFP”), and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.
The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $
253.4
million and a roughly
8
% increase to the typical residential customer’s bill. The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.
Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association (“AriSEIA”), Solar Energy Industries Association (“SEIA”), and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. A limited rehearing was held October 28 through November 1, 2024. Following the limited rehearing, an Administrative Law Judge issued a ROO (the “Limited Rehearing ROO”) on December 3, 2024. The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers. On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing. The Commission has taken no action on these requests. In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.
23
Coal Community Transition
On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) for an annual increase in retail base rates.
As a part of the 2019 Rate Case decision, the ACC approved the Coal Community Transition (“CCT”) Plan consisting of payments to certain impacted communities. APS has completed the following payments that are being recovered through rates related to CCT Plan: (i) $
10
million to the Navajo Nation; (ii) $
0.5
million to the Navajo County communities; and (iii) $
1
million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $
2
million to the Navajo Nation for CCT; (ii) $
1.1
million to the Navajo County communities for CCT and economic development; and (iii) $
1.25
million to the Hopi Tribe for CCT and economic development. The ACC also authorized $
1.25
million to be spent for electrification of homes and businesses on each of the Navajo Nation and Hopi reservations. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory. The census work was completed in November 2022 and disbursement of the funds for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed. On February 22, 2024, the ACC voted to not approve any further CCT funding.
Regulatory Lag Docket
On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates. On December 3, 2024, the ACC approved a policy statement regarding formula rate plans. The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases. On March 28, 2025, the Residential Utility Consumer Office filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. APS cannot predict the outcome of this matter.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.
See “2022 Retail Rate Case”
above for modifications of adjustment mechanisms in the 2022 Rate Case.
Renewable Energy Standard (“RES”)
Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including, for example, solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a
five-year
implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.
On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $
86.2
million, excluding any funding offsets. This budget contained funding for programs to comply with ACC-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal
24
supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2023. On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.
On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $
95.1
million.
APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023.
The ACC has not yet ruled on the 2024 RES Implementation Plan. APS cannot predict the outcome of this proceeding.
On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $
92.7
million.
APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2024.
The ACC has not yet ruled on the 2025 RES Implementation Plan. APS cannot predict the outcome of this proceeding.
On June 14, 2021, APS filed an application for approval of its Green Power Partners Program (“GPP”). On September 1, 2021, the ACC approved the application. On June 28, 2024, APS filed an application for approval of modifications to the GPP and requested a renewable generation renewable energy credits waiver. The ACC has not yet ruled on the GPP application. APS cannot predict the outcome of this proceeding.
Demand Side Management Adjustor Charge
The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan annually for review and approval by the ACC.
Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism.
See below for discussion of the LFCR.
On December 17, 2021, APS filed
its 2022 D
SM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM Implementation Plan requested a budget of
$
78.4
million.
On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive.
On June 1, 2022, APS filed its 2023 Transportation Electrification Plan (“2023 TE Plan”). The 2023 TE Plan detailed APS’s efforts to support transportation electrification in Arizona, including the Take Charge AZ Pilot Program and customer education and outreach related to transportation electrification. Subsequently, APS filed an amended 2023 TE Plan on November 30, 2022, that included a request for a $
5
million budget. On December 12, 2023, the ACC approved the 2023 TE Plan without including the Take Charge AZ Program and its budget going forward, but allowed APS to complete projects already underway. Additionally, the ACC discontinued the residential EV SmartCharger rebate and approved modifications to the EV rate plan.
25
On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $
88
million. On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan. The amended plan maintained the originally proposed budget of $
88
million. Subsequent to filing the amended 2023 DSM Implementation Plan and prior to the ACC approving it, on November 30, 2023, APS filed its 2024 DSM Implementation Plan. The 2024 DSM Implementation Plan requested a total budget of $
91.5
million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 Transportation Electrification (“TE”) Implementation Plan. On April 26, 2024, APS filed an amendment to the 2024 DSM Implementation Plan. The amended 2024 DSM Implementation Plan includes an updated budget of $
90.9
million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot. The ACC has not yet ruled on the amended 2024 DSM Implementation Plan. In a letter filed May 31, 2024, APS said it would not file a 2025 DSM Implementation Plan pending ACC review of the amended 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.
On August 30, 2024, APS filed an application for a new Bring-Your-Own-Device (“BYOD”) Battery Pilot Plan of Administration with the ACC as required by Decision No. 79293. This plan would allow APS to work with residential customers to enable APS to dispatch participating batteries and use them to provide demand response capacity to the grid. On March 20, 2025, the ACC approved the BYOD Plan of Administration. The BYOD program will be incorporated into future DSM plan filings.
On March 6, 2025, APS filed an application to refund uncommitted surcharge funds that were collected through the DSMAC and REAC adjustors. On April 22, 2025, the ACC voted to approve the refund of the DSMAC and REAC uncommitted surcharge funds. This refund will be provided directly to customers during the months of July and August 2025. The proposed rates are designed to refund customers $
9
million for DSMAC and $
43
million for REAC, although the actual refund amount is dependent upon monthly usage billed.
Power Supply Adjustor Mechanism and Balance
The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
•
APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
•
an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
•
the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•
the PSA rate includes (a) a “forward component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “historical component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the forward component are recovered during the next PSA Year; and (c) a “transition component,” under which APS may seek mid-
26
year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the forward component; and
•
the PSA rate may not be increased or decreased more than $
0.006
per kWh in a year without permission of the ACC.
The following table shows the changes in the deferred fuel and purchased power regulatory asset (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Balance at beginning of period | $ |
|
$ |
|
|||||||
| Deferred fuel and purchased power costs |
|
|
|||||||||
|
Amounts charged to customers
|
(
|
(
|
|||||||||
| Balance at end of period | $ |
|
$ |
|
|||||||
On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022.
That rate was $
0.007544
per kWh, which consisted of a forward component of $(
0.004842
) per kWh and a historical component of $
0.012386
per kWh.
The 2022 PSA rate was a $
0.004
per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA.
These rates went into effect as filed on February 1, 2022.
On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. In this filing, APS also requested that one of three different options be adopted to address the growing undercollected PSA balance. On February 23, 2023, the ACC approved an overall PSA rate of $
0.019074
per kWh, which consisted of a forward component of $(
0.005527
) per kWh, a historical component of $
0.013071
per kWh.
On November 30, 2023, APS notified the ACC that it will be maintaining a PSA rate of $
0.019074
per kWh and an updated PSA adjustment schedule would not be filed at that time. In Decision No. 79293 in the 2022 Rate Case, the ACC approved a permanent increase in the annual PSA adjustor rate cap from $
0.004
per kWh to $
0.006
per kWh and a requirement that APS report to the ACC for possible action when the overall PSA balance reaches $
100
million. As part of the 2022 Rate Case decision, the ACC also approved an overall PSA rate of $
0.011977
per kWh, which consisted of a forward component of $(
0.012624
) per kWh, a historical component of $
0.013071
per kWh, and a transition component of $
0.011530
per kWh. The overall PSA rate was reduced to offset an increase in base fuel prices. The rate became effective on March 8, 2024.
On November 27, 2024, APS filed its PSA rate for the PSA year beginning February 1, 2025. The overall PSA rate of $
0.013977
per kWh consists of a forward component of $(
0.000281
) per kWh, a historical component of $
0.008728
per kWh, and a transition component of $
0.005530
. This overall PSA rate is an increase of $
0.002
per kWh over the prior overall rate approved in the 2022 Rate Case decision, and it is below the annual PSA rate increase cap of $
0.006
per kWh. On February 5, 2025, the ACC voted to approve this request, with a rate effective date of the first billing cycle in March 2025.
Environmental Improvement Surcharge (“EIS”)
On March 5, 2024, because the ACC approved the elimination of the EIS, the surcharge is no longer in effect and any remaining amounts are being collected through base rates. The EIS permitted APS
27
to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.
Transmission Rates, Transmission Cost Adjustor (“TCA”) and Other Transmission Matters
APS’s retail transmission charges’ formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated with FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.
Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $
33
million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula.
Of this net amount, wholesale customer rates decreased by approximately $
6.4
million and retail customer rates would have decreased by approximately $
26.6
million.
However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $
2.4
million, resulting in a reduction to the residential rate and increases to commercial rates.
An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.
Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $
34.7
million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula.
Of this net amount, wholesale customer rates increased by approximately $
20.7
million and retail customer rates would have increased by approximately $
14
million.
However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $
10
million, resulting in reductions to the residential and commercial rates.
An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.
Effective June 1, 2024, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $
27.4
million for the 12-month period beginning June 1, 2024 in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $
16.6
million and retail customer rates would have increased by approximately $
10.8
million.
However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement increased by $
8.8
million, resulting in an increase to residential and commercial rates over
3
MW and a decrease to commercial rates less than or equal to
3
MW. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2024.
28
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation (“DG”) such as rooftop solar arrays. The adjustment to the LFCR has a year-over-year cap of
1
% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.
On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $
59.1
million (a $
32.5
million increase from previous levels, which was inclusive of a $
11.8
million balance from APS’s 2021 LFCR filing).
On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration.
On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.
On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff agreed to move the filing date for the annual LFCR adjustment to July 31 each year. On September 5, 2023, APS filed an updated LFCR Plan of Administration, which was approved by ACC Staff on December 8, 2023. On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that the annual LFCR recovery amount be increased to $
68.7
million (a $
9.6
million increase from previous levels). On October 19, 2023, a request for intervention was filed, which was granted. Consistent with an October 25, 2023 Procedural Order, the parties met and conferred and conducted limited discovery. As a result of Decision No. 79293 in the 2022 Rate Case, APS transferred $
27.1
million from the LFCR to base rates.
On March 8, 2024, APS filed conforming LFCR schedules to incorporate changes required as a result of Decision No. 79293 in the 2022 Rate Case.
On April 9, 2024, the ACC approved the 2023 annual LFCR adjustment, with new rates effective in the first billing cycle of May 2024.
On June 5, 2024, APS filed a revised LFCR Plan of Administration in accordance with Decision No. 79293. The ACC approved the revised Plan of Administration on October 8, 2024.
On July 31, 2024, APS filed its 2024 annual LFCR adjustment, requesting that effective November 1, 2024, the annual LFCR recovery amount be increased to $
49.6
million (an $
8
million increase from previous levels). On December 3, 2024, the ACC approved the 2024 annual LFCR adjustment, with new rates effective in the first billing cycle of January 2025.
Tax Expense Adjustor Mechanism (“TEAM”)
The TEAM helps address potential federal income tax reform and enable the pass-through of certain income tax effects to customers.
The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. Currently, the TEAM is set to a zero rate as per Decision No. 79293.
29
Court Resolution Surcharge
Following an appeal of the 2019 Rate Case decision, the ACC approved a Court Resolution Surcharge (“CRS”) mechanism that permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of selective catalytic reduction (“SCR”) technology for Four Corners Units 4 and 5 and a change in APS’s allowable return on equity as required by the Arizona Court of Appeals and approved by the ACC in Decision No. 78979.
The CRS went into effect on July 1, 2023, at a rate of $
0.00175
per kWh.
The rate is designed to recover $
59.6
million in revenue lost by APS between December 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates.
The portion of the CRS representing the recovery of the $
59.6
million of lost revenue between December 2021 and June 20, 2023, $
29.5
million of which has been collected as of March 31, 2025, will cease upon full collection of the lost revenue.
Additionally, the CRS tariff was updated to remove the return on equity component and account for SCR-related depreciation and deferral adjustments approved in Decision No. 79293 in the 2022 Rate Case.
Net Metering
Payments by APS for energy exported to the grid from residential DG solar facilities are determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket.
The
RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects. The price established by this RCP method is updated annually (between general retail rate cases) but cannot be decreased by more than
10
% per year.
On April 29, 2022, APS filed an application to decrease the RCP price from
9.4
cents per kWh, which had been in effect since October 1, 2021, to
8.46
cents per kWh, reflecting a
10
% annual reduction, to become effective September 1, 2022.
On July 12, 2022, the ACC approved the RCP as filed.
On May 1, 2023, APS filed an application for revisions to the RCP.
This application would decrease the RCP price to
7.619
cents per kWh, reflecting a
10
% annual reduction, to become effective September 1, 2023.
On August 25, 2023, the ACC approved the RCP as filed.
On May 1, 2024, APS filed an application for revisions to the RCP.
This application would decrease the RCP price to
6.857
cents per kWh, reflecting a
10
% annual reduction, to become effective September 1, 2024.
On August 13, 2024, the ACC approved the RCP as filed.
On October 11, 2023, the ACC voted to open a new general docket to hold a hearing to explore potential future changes to the
10
% annual reduction cap in the solar export rate paid by utilities to distributed solar customers for exports to the grid and the
10
-year rate lock period for those customers that were approved in the ACC’s Value and Cost of Distributed Generation Docket. A procedural conference was held on November 1, 2023, to discuss the process going forward. As a result of the procedural conference, ACC Staff issued a request for information to investigate the issues related to this matter. A status conference was held on March 20, 2024 to determine if ACC Staff is prepared to present a recommendation on this matter at that time. Stakeholders provided responses to the ACC Staff’s request for information on March 21, 2024. Another status conference took place on May 20, 2024 and ACC Staff issued a request for additional information to investigate the issues related to the matter on May 31, 2024.
30
Stakeholders provided responses to the ACC Staff’s request for additional information on July 1, 2024, and on October 15, 2024, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes to the RCP at this time. The ACC Staff also recommended that the ACC close the docket without a hearing or further action. On March 19, 2025, the ACC Hearing Division filed a ROO that agreed with Staff’s recommendation to close the docket. The ACC has not yet acted on the ACC Staff’s recommendation. APS cannot predict the outcome of this matter.
Energy Modernization Plan
On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the RES, and energy efficiency standards (“EES”). On January 9, 2024, the ACC approved the opening of new dockets to begin rulemaking process for EES and RES. It was also ordered that an existing rulemaking docket would be utilized to review proposed updates to the ASRFP and Resource Planning Rules. During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current EES and RES rules during the rulemaking process. On August 21, 2024, the ACC Staff filed separate reports for each set of rules, including its recommendations to repeal the EES and RES rules along with required preliminary economic, small business, and consumer impact statements. APS and other interested parties have filed comments about the ACC Staff reports. APS cannot predict the outcome of this matter.
Integrated Resource Planning (“IRP”)
ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan time frame. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020. The ACC also approved certain amendments to the IRP process, including setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030.
On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc. filed a joint request for an extension to file the IRPs from August 1, 2023, to November 1, 2023.
On June 21, 2023, the ACC granted the extension.
As a result, APS filed its 2023 IRP on November 1, 2023.
On January 31, 2024, stakeholders filed comments regarding the IRP, and APS filed its response to stakeholder comments on May 31, 2024. On July 31, 2024, the ACC held an IRP workshop where utilities and stakeholders presented on the 2023 IRPs. On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate resource adequacy prior to exiting Four Corners as well as analysis of impacts from western market participation and planned resource requirements in the next IRP.
Residential Electric Utility Customer Service Disconnections
In accordance with the ACC’s service disconnection rules, APS uses a calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Since the Annual Disconnection Moratorium began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts. Pursuant to an ACC order, customers with past due balances of $
75
or greater as of approximately one month prior to the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements.
31
Cholla ACC Deferral Request
On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s if the U.S. Environmental Protection Agency (“EPA”) approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.
On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit.
APS closed Unit 2 on October 1, 2015.
In early 2017, the EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017.
In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020.
APS was required to cease burning coal at its remaining Cholla units by April 2025.
Previously, APS estimated Cholla Unit 2’s end of life to be 2033.
APS is allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $
27
million as of March 31, 2025, in addition to a return on its investment.
In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to regulatory assets.
In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.
On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of Cholla Units 1 and 3. This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, coal combustion residuals (“CCR”) corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. APS cannot predict the outcome of this matter.
Navajo Plant
The Navajo Plant ceased operations in November 2019.
The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations.
In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to regulatory assets.
APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026.
Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant, $
31
million as of March 31, 2025, in addition to a return on the net book value, with the exception of
15
% of the annual amortization expense in rates.
In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset, $
5.7
million as of March 31, 2025. The disallowed recovery of
15
% of the annual amortization does not have a material impact on APS financial statements.
32
Fire Mitigation
On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs. APS cannot predict the outcome of this matter.
Regulatory Assets and Liabilities
The detail of regulatory assets is as follows (dollars in thousands):
| Amortization Through |
March 31,
2025 |
December 31,
2024 |
|||||||||||||||
| Pension | (a) | $ |
|
$ |
|
||||||||||||
| Deferred fuel and purchased power (b) (c) | 2026 |
|
|
||||||||||||||
| Income taxes — allowance for funds used during construction equity | 2054 |
|
|
||||||||||||||
| Ocotillo deferral | 2034 |
|
|
||||||||||||||
| Lease incentives | (g) |
|
|
||||||||||||||
| SCR deferral (e) | 2038 |
|
|
||||||||||||||
| Retired power plant costs | 2033 |
|
|
||||||||||||||
| FERC Transmission true up | 2027 |
|
|
||||||||||||||
| Income taxes — investment tax credit basis adjustment | 2056 |
|
|
||||||||||||||
| Deferred compensation | 2036 |
|
|
||||||||||||||
| Deferred property taxes | 2027 |
|
|
||||||||||||||
|
Palo Verde VIEs (Note 8)
|
2046 |
|
|
||||||||||||||
| Mead-Phoenix transmission line contributions in aid of construction (“CIAC”) | 2050 |
|
|
||||||||||||||
| Active Union Medical Trust | (f) |
|
|
||||||||||||||
| Loss on reacquired debt | 2038 |
|
|
||||||||||||||
| Navajo coal reclamation | 2026 |
|
|
||||||||||||||
| Tax expense adjustor mechanism (b) | 2031 |
|
|
||||||||||||||
| PSA - interest | 2026 |
|
|
||||||||||||||
|
Deferred fuel and purchased power — mark-to-market (Note 9)
|
|
|
|||||||||||||||
| Other | Various |
|
|
||||||||||||||
| Total regulatory assets (d) | $ |
|
$ |
|
|||||||||||||
| Less: current regulatory assets | $ |
|
$ |
|
|||||||||||||
| Total non-current regulatory assets | $ |
|
$ |
|
|||||||||||||
(a)
This asset represents the future recovery of pension benefit obligations and expense through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income and result in lower future revenues. As a result of the 2019 Rate Case decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. Subsequently, the 2022 Rate Case decision allowed for the full return on the pension asset in rate base. See Note 7 for further discussion.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
Subject to a carrying charge.
(d)
There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
33
(e)
See “Court Resolution Surcharge” discussion above.
(f)
Collected in retail rates.
The detail of regulatory liabilities is as follows (dollars in thousands):
| Amortization Through |
March 31,
2025 |
December 31,
2024 |
|||||||||||||||
| Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a) | 2046 | $ |
|
$ |
|
||||||||||||
| Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a) | 2058 |
|
|
||||||||||||||
| Asset retirement obligations and removal costs | (d) |
|
|
||||||||||||||
| Other postretirement benefits | (c) |
|
|
||||||||||||||
| Four Corners coal reclamation | 2038 |
|
|
||||||||||||||
|
Deferred fuel and purchased power — mark-to-market (Note 9)
|
2028 |
|
|
||||||||||||||
| Renewable energy standard (b) | 2026 |
|
|
||||||||||||||
| Income taxes — deferred investment tax credit | 2056 |
|
|
||||||||||||||
| Income taxes — change in rates | 2053 |
|
|
||||||||||||||
| Demand side management (b) | 2025 |
|
|
||||||||||||||
| Spent nuclear fuel | 2027 |
|
|
||||||||||||||
| Sundance maintenance | 2031 |
|
|
||||||||||||||
| TCA Balancing Account (b) | 2026 |
|
|
||||||||||||||
| Property tax deferral | 2027 |
|
|
||||||||||||||
| Tax expense adjustor mechanism (b) | 2032 |
|
|
||||||||||||||
| Other | Various |
|
|
||||||||||||||
| Total regulatory liabilities | $ |
|
$ |
|
|||||||||||||
| Less: current regulatory liabilities | $ |
|
$ |
|
|||||||||||||
| Total non-current regulatory liabilities | $ |
|
$ |
|
|||||||||||||
(a)
For purposes of presentation on the Statements of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)
See “Cost Recovery Mechanisms” discussion above.
(c)
See Note 7.
(d)
In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
7.
Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. The other postretirement benefit plans include a group life and medical plan and a post-65 retiree health reimbursement arrangement (“HRA”). Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.
34
The following table provides detail of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
| Pension Plans | Other Benefits Plans | ||||||||||||||||||||||
| Three Months Ended March 31, | Three Months Ended March 31, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Service cost-benefits earned during the period | $ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||
|
Non-service costs (credits):
|
|||||||||||||||||||||||
| Interest cost on benefit obligation |
|
|
|
|
|||||||||||||||||||
| Expected return on plan assets |
(
|
(
|
(
|
(
|
|||||||||||||||||||
| Amortization of: | |||||||||||||||||||||||
| Prior service credit (a) |
|
|
(
|
(
|
|||||||||||||||||||
|
Net actuarial loss (gain)
|
|
|
(
|
(
|
|||||||||||||||||||
|
Net periodic benefit costs (credits)
|
$ |
|
$ |
|
$ |
(
|
$ |
(
|
|||||||||||||||
|
Portion of costs (credits) charged to expense
|
$ |
|
$ |
|
$ |
(
|
$ |
(
|
|||||||||||||||
(a) Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 and they became fully amortized as of January 31, 2025.
Contributions
8.
Variable Interest Entities
Pinnacle West
Captive Insurance Cell VIE
To support our overall insurance program, Pinnacle West established a captive insurance cell to insure certain risks of Pinnacle West and our subsidiaries.
The Captive is a protected separate cell captive insurance company sponsored by Energy Insurance Services, Inc (“EISI”).
EISI is owned by Energy Insurance Mutual Limited Company and allows participating member sponsoring organizations, such as Pinnacle West, to insure risks using captive entities.
Pinnacle West, through its contractual rights, has a controlling financial interest in the separate protected Captive cell’s assets. Pinnacle West obtains all the benefits from the Captive and makes all the primary controlling decisions that economically impact the Captive.
As a separate protected cell, Pinnacle West is the Captive’s only participant. The Captive is a VIE for which Pinnacle West is the primary beneficiary.
Accordingly, Pinnacle West consolidates the Captive.
35
Under a mutual business program participation agreement between the Captive and EISI, EISI will issue policies, make claim disbursements, claim expenses and other underwriting fees on behalf of the Captive, as necessary.
The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. The Captive policies exclude nuclear liability at Palo Verde. See Note 10 for details regarding nuclear liability insurance. Claim payments to the insureds can only be made up to the amount of the Captive’s available assets. In the event that claims exceed the Captive’s available assets, Pinnacle West may be required to provide additional funding to the Captive. In addition to policies obtained through the Captive, Pinnacle West also has insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs.
As a result of consolidation, we eliminate intercompany transactions between Pinnacle West and the Captive and record the Captive’s assets, liabilities and third-party operating activities. In consolidation, the Captive’s insurance premium revenues derived from Pinnacle West policies are eliminated against the insurance premium expense recorded by Pinnacle West and our subsidiaries relating to insurance policy coverage provided by the Captive. Consolidation primarily resulted in Pinnacle West reflecting the Captive’s investment holdings on its Condensed Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on Pinnacle West’s Condensed Consolidated Statements of Income.
Consolidation of the Captive resulted in an increase in Pinnacle West’s net income for the three months ended March 31, 2025 and March 31, 2024 of $
0.7
million and
zero
, respectively. Amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts the Pinnacle West Condensed Consolidated Income Statement’s operations and maintenance expense and other income line items.
Pinnacle West’s Condensed Consolidated Balance Sheets as of March 31, 2025 and December 31, 2024 include $
35
million and $
34
million, respectively, of assets relating to the Captive that is reported within the other special use funds line item. See Notes 13 and 14 for additional details on these investment holdings.
APS’s financial statements are not impacted by Pinnacle West’s consolidation of the Captive VIE.
APS
Palo Verde Sale Leaseback VIEs
In 1986, APS entered into agreements with
three
separate variable interest entities (“VIEs”) lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2033 under all
three
lease agreements.
APS will be required to make payments relating to the
three
leases in total of approximately
$
21
million
annually for the period 2025 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to
two years
, or return the assets to the lessors.
The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most
36
significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $
4
million for both the three months ended March 31, 2025 and 2024. The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.
Our Condensed Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):
| March 31, 2025 | December 31, 2024 | ||||||||||
| Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation | $ |
|
$ |
|
|||||||
| Equity — Noncontrolling interests |
|
|
|||||||||
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our Condensed Consolidated Financial Statements.
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the Nuclear Regulatory Commission (“NRC”)) issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written-down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $
345
million beginning in 2025, and up to $
501
million over the lease extension terms.
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
9.
Derivative Accounting
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options, and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.
37
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the Condensed Consolidated Balance Sheets as an asset or liability and are measured at fair value. See Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery, and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
See Note 12 for details relating to Pinnacle West’s equity forward sale agreements and Note 5 for Pinnacle West’s Convertible Notes. These equity-linked transactions are indexed to Pinnacle West common stock and qualify for a derivative scope exception, and as such, are not subject to mark-to-market accounting and are excluded from the derivative disclosures below.
Energy Derivatives
For its regulated operations, APS defers for future rate treatment
100
% of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. See Note 6. Gains and losses from energy derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):
| Quantity | |||||||||||||||||
| Commodity | Unit of Measure | March 31, 2025 | December 31, 2024 | ||||||||||||||
| Power | GWh |
|
|
||||||||||||||
| Gas | Billion cubic feet |
|
|
||||||||||||||
Gains and Losses from Energy Derivative Instruments
For the three months ended March 31, 2025 and 2024, APS had no energy derivative instruments in designated accounting hedging relationships.
| Financial Statement | Three Months Ended March 31, | |||||||||||||||||||
| Commodity Contracts | Location | 2025 | 2024 | |||||||||||||||||
|
Net Gain (Loss) Recognized in Income
|
Fuel and purchased power (a) | $ |
|
$ |
(
|
|||||||||||||||
(a)
Amounts are before the effect of PSA deferrals.
38
Energy Derivative Instruments in the Condensed Consolidated Balance Sheets
Our energy derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets.
We do not offset a counterparty’s current energy derivative contracts with the counterparty’s non-current energy derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.
The following tables provide information about the fair value of APS’s risk management activities reported on a gross basis and the impacts of offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of APS’s Condensed Consolidated Balance Sheets.
|
As of March 31, 2025:
(dollars in thousands) |
Gross
Recognized Derivatives (a) |
Amounts
Offset (b) |
Net
Recognized Derivatives |
Other
(c) |
Amounts
Reported on Balance Sheets |
|||||||||||||||||||||||||||
| Current assets | $ |
|
$ |
(
|
$ |
|
$ |
|
$ |
|
||||||||||||||||||||||
| Investments and other assets |
|
(
|
|
|
|
|||||||||||||||||||||||||||
| Total assets |
|
(
|
|
|
|
|||||||||||||||||||||||||||
| Current liabilities |
(
|
|
(
|
(
|
(
|
|||||||||||||||||||||||||||
| Deferred credits and other |
(
|
|
(
|
|
(
|
|||||||||||||||||||||||||||
| Total liabilities |
(
|
|
(
|
(
|
(
|
|||||||||||||||||||||||||||
| Total | $ |
|
$ |
|
$ |
|
$ |
(
|
$ |
|
||||||||||||||||||||||
(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No
cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $
4,196
thousand and cash margin provided to counterparties of $
5
thousand.
39
|
As of December 31, 2024:
(dollars in thousands) |
Gross
Recognized Derivatives (a) |
Amounts
Offset (b) |
Net
Recognized Derivatives |
Other
(c) |
Amounts
Reported on Balance Sheets |
|||||||||||||||||||||||||||
| Current assets | $ |
|
$ |
(
|
$ |
|
$ |
|
$ |
|
||||||||||||||||||||||
| Investments and other assets |
|
(
|
|
|
|
|||||||||||||||||||||||||||
| Total assets |
|
(
|
|
|
|
|||||||||||||||||||||||||||
| Current liabilities |
(
|
|
(
|
(
|
(
|
|||||||||||||||||||||||||||
| Deferred credits and other |
(
|
|
(
|
|
(
|
|||||||||||||||||||||||||||
| Total liabilities |
(
|
|
(
|
(
|
(
|
|||||||||||||||||||||||||||
| Total | $ |
(
|
$ |
|
$ |
(
|
$ |
(
|
$ |
(
|
||||||||||||||||||||||
(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No
cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $
2,971
thousand and cash margin provided to counterparties of $
18
thousand.
Credit Risk and Credit Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of March 31, 2025, we have three counterparties for which our exposure represents approximately
59
% of Pinnacle West’s $
108.9
million of risk management assets. This exposure relates to ISDA master agreements with the respective counterparties. The counterparties are rated as investment grade by Standard & Poor’s. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated results of operations for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
40
The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):
| March 31, 2025 | |||||
| Aggregate fair value of derivative instruments in a net liability position | $ |
|
|||
| Additional collateral in the event credit-risk related contingent features were fully triggered (a) |
|
||||
(a)
This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
We also have energy related non-derivative instrument contracts, including energy storage lease contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $
416
million if our debt credit ratings were to fall below investment grade.
10.
Commitments and Contingencies
Palo Verde Generating Station
Spent Nuclear Fuel and Waste Disposal
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the
U.S. Department of Energy (“DOE”)
in the
U.S.
Court of Federal Claims (“Court of Federal Claims”).
The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.
On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011.
In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.
APS has recovered costs for
eleven
claims pursuant to the terms of the August 15, 2014 settlement agreement, for
eleven
separate time periods during July 1, 2011, through October 31, 2024. The DOE has approved and paid approximately $
174.3
million for these claims (APS’s share is approximately $
50.7
million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case decision, this regulatory liability is being refunded to customers.
Nuclear Insurance
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.
This insurance limit is subject to an adjustment every five years based upon the aggregate percentage change in the Consumer Price Index. The most recent adjustment took effect on January 1, 2024. As of that date, in accordance with the Price-Anderson Act, the Palo Verde participants are insured against public
41
liability for a nuclear incident up to approximately $
16.3
billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $
500
million, which is provided by American Nuclear Insurers. The remaining balance of approximately $
15.8
billion
of liability coverage is provided through a mandatory, industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately
$
165.9
million, subject to a maximum annual premium of approximately $
24.7
million per incident. Based on APS’s ownership interest in the
three
Palo Verde units, APS’s maximum retrospective premium per incident for all
three
units is approximately $
144.9
million, with a maximum annual retrospective premium of approximately $
21.6
million.
The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of
$
2.8
billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the
three
units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumul
ated funds. Th
e maximum amount APS could incur under the current NEIL policies totals approximately
$
24.2
million
for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $
66.4
million in deposit premium within
20
days of request as assurance to satisfy any site obligation of retrospective premium assessment. The insurance coverage discussed in this, and the previous paragraph, is subject to certain policy conditions, sublimits, and exclusions.
Captive Insurance Cell
Pinnacle West has established a captive insurance program to supplement third-party insurance coverage for certain risks. The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. These coverages may be supplemented with third-party insurance policies. The Captive policies exclude nuclear liability at Palo Verde. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments, which in the event of an insured loss would be available to pay covered claims. In the event of an insured loss event, Pinnacle West may be required to provide additional funding to the Captive. The Captive is a VIE, and Pinnacle West is the primary beneficiary of the VIE and consolidates the assets and liabilities of the Captive. See Note 8 for additional details.
Fuel and Purchased Power Commitments and Purchase Obligations
As of March 31, 2025,
there have been no material changes outside of the normal course of business in contractual obligations from the information provided in our
2024
Form 10-K. See Note
5
for discussion regarding changes in our short-term and long-term debt obligations.
Superfund and Other Related Matters
The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a
42
contaminated site are among the parties who are potentially responsible (each a “PRP”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. EPA notified APS that the RI/FS was approved on September 11, 2024. APS’s estimated costs related to this investigation and study are approximately
$
3
million.
APS anticipates incurring additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
In connection with APS’s status as a PRP for OU3, since 2013 APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”). At this time, only one active lawsuit remains pending in the U.S. District Court for Arizona, which concerns
$
8.3
million in remediation legal expenses. APS is unable to predict the outcome of any further litigation related to this claim or APS’s share of liability related to that claim; however, APS does not expect the outcome to have a material impact on its financial position, results of operations or cash flows.
On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona.
In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site.
The SIBW Superfund site includes the APS Ocotillo power plant site.
APS filed its response to this information request on April 29, 2022.
On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years.
APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $
1.7
million.
At the present time, we are unable to predict the outcome of this matter, and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.
Environmental Matters
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules could involve material compliance costs to APS.
43
Coal Combustion Waste
On December 19, 2014, the EPA issued its final regulations governing the handling and disposal of CCRs, such as fly ash and bottom ash.
The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.
These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.
The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.
Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.
Since these regulations were finalized, the EPA has taken steps to substantially modify the federal rules governing CCR disposal.
While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA.
The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:
•
Following the passage of the Water Infrastructure Improvements for the Nation (“WIIN”) Act in 2016, the EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program and proposed state regulations governing CCR permitting in the summer of 2024. On April 1, 2025, the Arizona Governor’s Regulatory Review Council approved ADEQ’s proposed rulemaking governing CCR permitting. ADEQ will submit an approval package to the EPA, which will have to approve the entire state program before it is operational. It remains unclear when the EPA would approve that permitting program pursuant to the WIIN Act. On December 19, 2019, the EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation. The proposal remains pending.
•
On March 1, 2018, as a result of a settlement with certain environmental groups, the EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities.
Apart from a subsequent proposal issued on August 14, 2019, to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.
•
With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to the EPA on November 30, 2020.
While the EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending.
If granted, this application would allow the continued disposal of CCRs within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025.
This application will be subject to public comment and, potentially, judicial review.
We
44
expect to have a proposed decision from EPA regarding Cholla in 2025.
APS’s Cholla plant ceased operations on March 17, 2025.
We cannot predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending.
Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.
On April 25, 2024, EPA took final action on a proposal to expand the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. This new class of CCR management units (“CCRMUs”), which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCRs would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use (with exceptions for historical roadbed and embankment applications). Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs. At this time, APS is still evaluating the impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027. Based on the information available to APS at this time, APS cannot reasonably estimate the cost of the entire CCRMU asset retirement obligation. Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows. In addition, the EPA under the current presidential administration has recently stated that it intends on prioritizing a number of timely actions on coal ash, including state permit program reviews and updates to the coal ash regulations. We cannot predict the outcome of a future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules.
APS currently disposes of CCR in ash ponds and dry storage areas at Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. The Cholla Plant disposed of CCR in ash ponds and dry storage areas prior to retirement. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such dispo
sal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units subject to alternative closure).
APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway.
In addition, APS has also solicited input from the public and hosted public hearings as part of this process.
APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations, Removal Costs and Regulatory Liabilities.
As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change.
Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, we cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate from the CCR rule’s corrective action assessment process for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.
45
EPA Power Plant Carbon Regulations
The EPA’s regulation of carbon dioxide emissions from electric utility power plants has proceeded in fits and starts over most of the last decade. Starting on August 3, 2015, the EPA finalized the Clean Power Plan, which was the agency’s first effort at such regulation through system-wide generation dispatch shifting. Those regulations were subsequently repealed by the EPA on June 19, 2019 and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules. While the U.S. Court of Appeals for the D.C. Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for the EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S. Supreme Court subsequently reversed that decision on June 30, 2022, holding that the Clean Power Plan exceeded the EPA’s authority under the Clean Air Act.
In the final regulations governing power plant carbon dioxide emissions, released April 25, 2024, the EPA issued emission standards and guidelines for various subcategories of new and existing power plants. Unlike the EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, these new federal regulations are limited to measures that can be installed at individual power plants to limit planet-warming carbon-dioxide emissions.
As such, for new natural gas-fired combustion turbine power plants, the EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, the EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) by 2032. For intermediate or low-load natural gas fired combustion turbines, those with 40% or less capacity factors, the EPA’s regulations would not require add-on pollution controls. Instead, natural gas-fired combustion turbines with capacity factors of up to 20% would be effectively unregulated, while such turbines with capacity factors over 20% and up to 40% would be subject to carbon dioxide emission rate limitations. EPA did not finalize standards for existing natural gas-fired combustion turbines but has indicated that it will propose a new set of standards, initiating a separate rulemaking, for these existing gas-fired power plants within the next year.
For coal-fired power plants, instead of imposing regulations based on capacity and utilization, the EPA has finalized subcategories based on planned retirement dates. This means that facilities retiring before 2032 are effectively exempt from regulation, those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030, and those that retire in 2039 or later must install CCS controls by 2032.
As of May 10, 2024, several states, electric utility companies, affiliated trade associations, and other entities filed petitions for review of these regulations in the D.C. Circuit Court of Appeals. APS is participating in that litigation as part of an ad hoc coalition of electric utility companies, independent power producers, and trade groups, called Electric Generators for a Sensible Transition. We cannot predict the outcome of the litigation challenging EPA’s latest carbon emission standards for power plants. In addition, the EPA under the current presidential administration recently stated that it intends to reverse or substantially revise these standards. We cannot predict the outcome of future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.
If this regulation remains in effect, it will likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants. The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install carbon capture and sequestration and
46
achieve 90% capture efficiency may not be feasible. Future resource plans and procurement efforts implicating the development of such new generation remains pending and, as such, at this time APS is not able to quantify the financial impact associated with the EPA’s GHG regulations for power plants.
Effluent Limitation Guidelines
The
EPA published effluent limitation guidelines (“ELG”) on October 13, 2020, and, based off those guidelines, APS completed a National Pollutant Discharge Elimination System (“NPDES”) permit modification for Four Corners on December 1, 2023. The ELG standards finalized in October 2020 relaxed the “zero discharge” standard for bottom ash transport waters the EPA finalized in September 2015. However, on April 25, 2024, the EPA finalized new ELG regulations that once again require “zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners. Nonetheless, for power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards. APS is currently evaluating its compliance options for Four Corners based on the ELG regulations finalized in April 2024 and is assessing what impacts the new
standards will have on our financial condition, results of operations, or cash flows. In addition, the EPA under the current presidential administration has announced that it intends to reconsider the ELG standards. We cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at modifying the current ELG standards.
EPA Good Neighbor Proposal for Arizona
On March 15, 2023, the EPA issued its final Good Neighbor Plan for 23 states in order to ensure that the cross-state transport of ozone forming emissions does not interfere with downwind state compliance with the National Ambient Air Quality Standards (“NAAQS”). Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide (“NOx”) emissions. While Arizona was not among the 23 states subject to the EPA’s March 2023 final action, EPA announced on January 23, 2024, that it was proposing to add Arizona and New Mexico (along with two other additional states) to the EPA’s NOx emission allowance trading program finalized last year. That proposal involves adding these states to the Good Neighbor Plan and disapproving the corresponding provisions of each state’s State Implementation Plan. Because APS operates thermal power plants within Arizona and those portions of the Navajo Nation within New Mexico, APS’s power plants would be subject to the EPA’s Good Neighbor Plan upon finalization of this proposal. The EPA’s final Good Neighbor Plan is subject to ongoing judicial review in the D.C. Circuit Court of Appeals.
On June 27, 2024, the U.S. Supreme Court granted a motion to stay the effectiveness of the EPA’s final Good Neighbor Plan pending the resolution of the litigation. As such, APS will not be impacted by the Good Neighbor Plan until the outcome of this litigation is finalized. In addition, on December 19, 2024, the EPA announced that it was withdrawing its proposal to add Arizona (along with other western states) to the federal Good Neighbor Plan. On March 12, 2025, the EPA under the current administration announced its intention to reconsider the Good Neighbor Plan. As such, while the EPA may elect to resume work on and finalize this proposal in the future, it is unlikely to do so over a near-term horizon. APS cannot predict the outcome of any future the EPA efforts to add Arizona to the federal Good Neighbor Plan (which depends on action disapproving the Arizona State Implementation Plan) or whether the Good Neighbor Plan itself will remain in effect pending the outcome of judicial review in the D.C. Circuit Court of Appeals. Should the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load. At this time, APS cannot predict the impact on the Company’s financial condition, results of operations, or cash flows.
47
Revised Mercury and Air Toxics Standard (“MATS”) Proposal
On April 25, 2024, the EPA finalized revisions to the existing MATS regulations governing
emissions of toxic air pollution from existing coal-fired power plants. The final regulations increase the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and require the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing). These final regulations will take effect for existing coal-fired power plants, such as Four Corners, within three years of publication in the Federal Register. Based on APS’s assessment of the revised MATS regulations, this final rule is unlikely to have a material impact on plant operations or require significant capital expenditures to ensure compliance. Additionally, the EPA under the current presidential administration has stated it intends to reconsider the MATS rules.
Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit
The latest NPDES permit for Four Corners was issued on September 30, 2019.
Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit.
The EAB denied the environmental group petition on
September 30, 2020.
The parties to the litigation (including APS) finalized a settlement on May 2, 2022.
This settlement requires investigation of thermal wastewater discharges from Four Corners and administratively closes the litigation filed in January 2021.
Financial Assurances
In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of March 31, 2025, standby letters of credit totaled approximately $
18.7
million and surety bonds totaled approximately $
22.8
million; both will expire through 2026. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be
48
reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material as of March 31, 2025. In connection with the sale of Pinnacle West’s wholly-owned subsidiary, 4C Acquisition, LLC’s
7
% interest in Units 4 and 5 of Four Corners to Navajo Transitional Energy Corporation (“NTEC”), Pinnacle West guaranteed certain obligations that NTEC has to the other owners of Four Corners. Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.
In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make production tax credit (“PTC”) funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. As of March 31, 2025, there is approximately $
28
million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2031.
Pinnacle West has issued various performance guarantees in connection with the Kūpono Solar Project investment financing and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote. These guarantees were issued in connection with Pinnacle West’s BCE subsidiary, which was sold to Ameresco in 2024 (the “BCE Sale”). See Note 18. Subsequent to the BCE Sale, Pinnacle West continues to maintain these Kūpono Solar Project investment financing guarantees. Under the Kūpono Solar Project sale-leaseback financing, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events, such as uninsured loss events. Ameresco, the owner of the Kūpono Solar Project, has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030. Pinnacle West has not needed to perform under these guarantees. Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated. Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees. We consider the fair value of these guarantees, including expected credit losses, to be immaterial.
49
11.
Other Income and Other Expense
The following table provides detail of Pinnacle West’s consolidated other income and other expense (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Other income: | |||||||||||
| Interest income (a) | $ |
|
$ |
|
|||||||
| Investment gain — net (b) |
|
|
|||||||||
|
Gain on sale of BCE (Note 18)
|
|
|
|||||||||
| Miscellaneous |
|
|
|||||||||
| Total other income | $ |
|
$ |
|
|||||||
| Other expense: | |||||||||||
| Non-operating costs | $ |
(
|
$ |
(
|
|||||||
| Investment losses — net |
|
(
|
|||||||||
| Miscellaneous |
(
|
(
|
|||||||||
| Total other expense | $ |
(
|
$ |
(
|
|||||||
(a)
Interest income is primarily related to PSA interest. See Note 6.
(b)
Investment gain is primarily related to El Dorado’s equity investment in SAI Advanced Power Solutions.
The following table provides detail of APS’s other income and other expense (dollars in thousands):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Other income: | |||||||||||
| Interest income (a) | $ |
|
$ |
|
|||||||
| Miscellaneous |
|
|
|||||||||
| Total other income | $ |
|
$ |
|
|||||||
| Other expense: | |||||||||||
| Non-operating costs | $ |
(
|
$ |
(
|
|||||||
| Miscellaneous |
(
|
(
|
|||||||||
| Total other expense | $ |
(
|
$ |
(
|
|||||||
(a)
Interest income is primarily related to PSA interest. See Note 6.
12.
Common Stock Equity and Earnings Per Share
ATM Program
On November 8, 2024, Pinnacle West entered into an equity distribution sales agreement, pursuant to which Pinnacle West may sell, from time to time, up to $
900
million of its common stock through an at-
50
the-market (“ATM”) equity distribution program, which includes the ability to enter into forward sale agreements. As of
March 31, 2025
, approximately $
800
million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreements in effect as of
March 31, 2025
.
As of
March 31, 2025
, Pinnacle West had
two
outstanding forward sale agreements under the ATM Program relating to approximately $
100
million of common stock. These agreements are the November 2024 ATM Forward Sale Agreement and the March 2025 ATM Forward Sale Agreement (collectively, the “ATM Forward Sale Agreements”), which may be settled at Pinnacle West’s discretion no later than June 30, 2026 and
September 14, 2026, respectively
. On a given settlement date, Pinnacle West will issue shares of common stock at the then-applicable forward sales price. Additionally, the terms of the forward sale agreements allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.
The following table presents the calculation of Pinnacle West’s ATM Program as of March 31, 2025 (in thousands, except share amounts and price per share):
|
As of March 31, 2025
|
|||||||||||
| November 2024 ATM Forward Sale Agreement | March 2025 ATM Forward Sale Agreement | ||||||||||
| Initial Price | |||||||||||
| Number of Shares |
|
|
|||||||||
| Forward Sales Price Per Share (a) | $ |
|
$ |
|
|||||||
| Aggregate Value (in thousands) | $ |
|
$ |
|
|||||||
(a) Subject to certain adjustments.
Non-ATM February 2024 Forward Sale Agreements
On February 28, 2024, Pinnacle West executed equity forward sale agreements (“February 2024 Forward Sale Agreements”). The February 2024 Forward Sale Agreements may be settled at Pinnacle West’s discretion no later than September 4, 2025, and were not issued under the ATM Program discussed above.
On a settlement date, Pinnacle West will issue shares of Pinnacle West common stock and receive cash, if any,
at the then-applicable forward sales price.
The terms of the February 2024 Forward Sale Agreements also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.
51
The following table presents the calculation of Pinnacle West’s February 2024 Forward Sale Agreements as of March 31, 2025 (in thousands, except share amounts and price per share):
|
As of March 31, 2025
|
|||||
| February 2024 Forward Sale Agreements | |||||
| Initial Price | |||||
| Number of Shares |
|
||||
| Forward Sales Price Per Share (a) | $ |
|
|||
| Aggregate Value (in thousands) | $ |
|
|||
| Settlements | |||||
| Date | 12/23/2024 | ||||
| Number of Shares Settled (b) |
|
||||
| Forward Sales Price Upon Settlement | $ |
|
|||
| Net Proceeds (in thousands) (c) | $ |
|
|||
(a) Subject to certain adjustments.
(b) Physical delivery.
(c) Proceeds recorded in common equity on the Condensed Consolidated Balance Sheets.
Convertible Notes
In June 2024, Pinnacle West issued $
525
million of
4.75
% Convertible Senior Notes due 2027, which are senior unsecured obligations of Pinnacle West, and will mature on June 15, 2027. The Convertible Notes bear interest at a fixed rate of
4.75
% per year, payable semiannually in arrears on June 15 and December 15 of each year, beginning on December 15, 2024.
Prior to March 15, 2027, the holders of the Convertible Notes may elect at their option to convert all or any portion of their Convertible Notes under the following limited circumstances:
•
during any calendar quarter (and only during such calendar quarter), if the sale price of Pinnacle West common stock for at least
20
trading days (whether or not consecutive) during a period of
30
consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter, is greater than or equal to
130
% of the conversion price on each applicable trading day;
•
during the
five
business day period after any
10
consecutive trading day period (“Measurement Period”) in which the trading price per $1,000 principal amount of Convertible Notes for each trading day of the Measurement Period was less than
98
% of the product of the last reported sale price of Pinnacle West common stock and the conversion rate on such trading day; or
•
upon the occurrence of certain corporate events, as defined in the Convertible Notes’ indenture.
On or after March 15, 2027, until the maturity date, the holders of the Convertible Notes may elect at their option to convert all or any portion of their notes. Upon conversion, Pinnacle West will pay cash up to the aggregate principal amount of the Convertible Notes converted and at Pinnacle West’s sole discretion, pay or deliver cash, shares of Pinnacle West common stock or a combination of both, in respect
52
to the remainder, if any, of Pinnacle West’s conversion obligation in excess of the aggregate principal amount of the Convertible Notes being converted. The initial conversion rate, which is subject to certain adjustments as set forth in the indenture, is 10.8338 shares of common stock per $1,000 principal amount of Convertible Notes, which is equivalent to an initial conversion price of approximately $
92.30
per share. The conversion rate is not subject to adjustment for any accrued and unpaid interest.
If Pinnacle West undergoes a fundamental change, as defined in the Convertible Notes’ indenture, then, subject to certain conditions, holders of the Convertible Notes may require Pinnacle West to repurchase for cash all or any portion of its Convertible Notes at a repurchase price equal to
100
% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.
As of March 31, 2025, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Condensed Consolidated Balance Sheets with a carrying amount of $
525
million, including unamortized debt issuance costs of $
6
million. The estimated fair value of the Convertible Notes as of March 31, 2025 was $
591
million (Level 2 within the fair value hierarchy).
As of March 31, 2025, based on Pinnacle West’s average stock price, the net loss position, and the relevant terms of the Convertible Notes, there were no shares of Pinnacles West’s common stock included in basic or diluted EPS relating to the potential conversion of the Convertible Notes.
53
Earnings Per Share
The following table presents the calculation of Pinnacle West’s basic and diluted EPS (in thousands, except earnings per share amounts):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Net income (loss) attributable to common shareholders | $ |
(
|
$ |
|
|||||||
| Weighted average common shares outstanding — basic |
|
|
|||||||||
| Net effect of dilutive securities: | |||||||||||
| Contingently issuable performance shares and restricted stock units |
|
|
|||||||||
| Dilutive shares related to equity forward sale agreements (a) |
|
|
|||||||||
| Total contingently issuable shares (b) |
|
|
|||||||||
| Weighted average common shares outstanding — diluted |
|
|
|||||||||
| Earnings per weighted-average common share outstanding | |||||||||||
| Net income (loss) attributable to common shareholders — basic | $ |
(
|
$ |
|
|||||||
| Net income (loss) attributable to common shareholders — diluted (b) | $ |
(
|
$ |
|
|||||||
(a) For the three months ended March 31, 2025 and 2024, diluted weighted average common shares excludes
197,390
and
0
shares, respectively, relating to the Convertible Notes and the November 2024 ATM Forward Sale Agreements. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.
13.
Fair Value Measurements
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:
54
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Recurring Fair Value Measurements
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 7 in the 2024 Form 10-K for fair value discussion of plan assets held in our retirement and other benefit plans.
Cash Equivalents
Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.
55
Risk Management Activities — Energy Derivative Instruments
Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Long-dated energy transactions may consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds
The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account, the active union employee medical account, and the Captive. See Note 14 for additional discussion about our investment accounts.
We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.
56
Fixed Income Securities
Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.
Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.
Equity Securities
The nuclear decommissioning trusts’ equity security investments are held indirectly through commingled funds. The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a daily basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.
The nuclear decommissioning trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid investments are valued using active market prices.
57
Fair Value Tables
The following table presents the fair value as of March 31, 2025 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||||||||||||||||
| ASSETS | |||||||||||||||||||||||||||||||||||
| Cash equivalents | $ |
|
$ |
|
$ |
|
$ | — | $ |
|
|||||||||||||||||||||||||
| Risk management activities — derivative instruments: | |||||||||||||||||||||||||||||||||||
| Commodity contracts |
|
|
|
(
|
(a) |
|
|||||||||||||||||||||||||||||
| Nuclear decommissioning trusts: | |||||||||||||||||||||||||||||||||||
| Equity securities |
|
|
|
|
(b) |
|
|||||||||||||||||||||||||||||
| U.S. commingled equity funds |
|
|
|
|
(c) |
|
|||||||||||||||||||||||||||||
| U.S. Treasury debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Corporate debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Mortgage-backed securities |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Municipal bonds |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Other fixed income |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Subtotal nuclear decommissioning trusts |
|
|
|
|
|
||||||||||||||||||||||||||||||
| Other special use funds: | |||||||||||||||||||||||||||||||||||
| Equity securities |
|
|
|
|
(b) |
|
|||||||||||||||||||||||||||||
| U.S. Treasury debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Subtotal other special use funds (d) |
|
|
|
|
|
||||||||||||||||||||||||||||||
| Total assets | $ |
|
$ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||||||||||||
| LIABILITIES | |||||||||||||||||||||||||||||||||||
| Risk management activities — derivative instruments: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ |
|
$ |
(
|
$ |
(
|
$ |
(
|
(a) | $ |
(
|
||||||||||||||||||||||||
(a)
Represents counterparty netting, margin, and collateral. See Note 9.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)
All amounts relate to APS, with the exception of $
35.1
million related to Pinnacle West’s Captive investments that are classified within Level 1, $
10.0
million related to equity securities and $
25.1
million related to U.S. treasury debt. See Note 8.
58
The following table presents the fair value at December 31, 2024 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
| Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||||||||||||||||
| ASSETS | |||||||||||||||||||||||||||||||||||
| Cash equivalents | $ |
|
$ |
|
$ |
|
$ | — | $ |
|
|||||||||||||||||||||||||
| Risk management activities — derivative instruments: | |||||||||||||||||||||||||||||||||||
| Commodity contracts |
|
|
|
(
|
(a) |
|
|||||||||||||||||||||||||||||
| Nuclear decommissioning trusts: | |||||||||||||||||||||||||||||||||||
| Equity securities |
|
|
|
|
(b) |
|
|||||||||||||||||||||||||||||
| U.S. commingled equity funds |
|
|
|
|
(c) |
|
|||||||||||||||||||||||||||||
| U.S. Treasury debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Corporate debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Mortgage-backed securities |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Municipal bonds |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Other fixed income |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Subtotal nuclear decommissioning trusts |
|
|
|
|
|
||||||||||||||||||||||||||||||
| Other special use funds: | |||||||||||||||||||||||||||||||||||
| Cash equivalents |
|
|
|
|
(d) |
|
|||||||||||||||||||||||||||||
| Equity securities |
|
|
|
|
(b) (d) |
|
|||||||||||||||||||||||||||||
| U.S. Treasury debt |
|
|
|
— |
|
||||||||||||||||||||||||||||||
| Subtotal other special use funds (d) |
|
|
|
|
|
||||||||||||||||||||||||||||||
| Total assets | $ |
|
$ |
|
$ |
|
$ |
|
$ |
|
|||||||||||||||||||||||||
| LIABILITIES | |||||||||||||||||||||||||||||||||||
| Risk management activities — derivative instruments: | |||||||||||||||||||||||||||||||||||
| Commodity contracts | $ |
|
$ |
(
|
$ |
(
|
$ |
|
(a) | $ |
(
|
||||||||||||||||||||||||
(a)
Represents counterparty netting, margin, and collateral. See Note 9.
(b)
Represents net pending securities sales and purchases.
(c)
Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
(d)
All amounts relate to APS, with the exception of $
34.2
million related to Pinnacle West’s Captive investments that are classified within Level 1, $
25.0
million in cash equivalents and $
9.2
million related to equity securities. See Note 8.
Fair Value Measurements Classified as Level 3
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment.
59
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments as of March 31, 2025 and December 31, 2024:
|
March 31, 2025
Fair Value (thousands) |
Valuation | Significant | Weighted-Average | ||||||||||||||||||||||||||||||||||||||
| Commodity Contracts | Assets | Liabilities | Technique | Unobservable Input | Range | (b) | |||||||||||||||||||||||||||||||||||
| Electricity Forward Contracts (a) | $ |
|
$ |
|
Discounted cash flows | Electricity forward price (per MWh) |
$
|
- |
$
|
$
|
|||||||||||||||||||||||||||||||
| Natural Gas Forward Contracts (a) |
|
|
Discounted cash flows | Natural gas forward price (per MMBtu) |
$(
|
- |
$
|
$
|
|||||||||||||||||||||||||||||||||
| Total | $ |
|
$ |
|
|||||||||||||||||||||||||||||||||||||
(a)
Includes swaps and physical and financial contracts.
(b)
Unobservable inputs were weighted by the relative fair value of the instrument.
|
December 31, 2024
Fair Value (thousands) |
Valuation | Significant | Weighted-Average | ||||||||||||||||||||||||||||||||||||||
| Commodity Contracts | Assets | Liabilities | Technique | Unobservable Input | Range | (b) | |||||||||||||||||||||||||||||||||||
| Electricity Forward Contracts (a) | $ |
|
$ |
|
Discounted cash flows | Electricity forward price (per MWh) | $ |
|
- |
$
|
$
|
||||||||||||||||||||||||||||||
| Natural Gas Forward Contracts (a) |
|
|
Discounted cash flows | Natural gas forward price (per MMBtu) |
$(
|
- |
$
|
$
|
|||||||||||||||||||||||||||||||||
| Total | $ |
|
$ |
|
|||||||||||||||||||||||||||||||||||||
(a)
Includes swaps and physical and financial contracts.
(b)
Unobservable inputs were weighted by the relative fair value of the instrument.
60
The following table shows the changes in fair value for our risk management activities’ assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs (dollars in thousands):
| Three Months Ended March 31, | ||||||||||||||
| Commodity Contracts | 2025 | 2024 | ||||||||||||
| Balance at beginning of period | $ |
(
|
$ |
|
||||||||||
| Total net losses realized/unrealized: | ||||||||||||||
| Deferred as a regulatory asset or liability |
(
|
(
|
||||||||||||
| Settlements |
(
|
|
||||||||||||
| Transfers into Level 3 from Level 2 |
(
|
|
||||||||||||
| Transfers from Level 3 into Level 2 |
|
|
||||||||||||
| Balance at end of period | $ |
(
|
$ |
(
|
||||||||||
| Net unrealized gains/losses included in earnings related to instruments still held at end of period | $ |
|
$ |
|
||||||||||
|
Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.
|
||
Financial Instruments Not Carried at Fair Value
14.
Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
We have investments in debt and equity securities held in nuclear decommissioning trusts and other special use funds. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Condensed Consolidated Balance Sheets. See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.
Nuclear Decommissioning Trusts
APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities.
Coal Reclamation Escrow Account
APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds
61
from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.
Active Union Employee Medical Account
APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2024, APS was reimbursed $
14
million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory assets and liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.
Captive Insurance Cell
Pinnacle West has investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments. These investments are restricted for insured loss events.
Pinnacle West Consolidated investment holdings reflected in the tables below primarily relate to APS, with the exception of the Captive’s investments included within other special use funds.
The following tables present the unrealized gains and losses based on the original cost of the investment and summarize the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands):
| March 31, 2025 | |||||||||||||||||||||||||||||
| Fair Value |
Total
Unrealized Gains |
Total
Unrealized Losses |
|||||||||||||||||||||||||||
| Investment Type: | Nuclear Decommissioning Trusts | Other Special Use Funds | Total | ||||||||||||||||||||||||||
| Equity securities | $ |
|
$ |
|
$ |
|
$ |
|
$ |
(
|
|||||||||||||||||||
| Available for sale-fixed income securities |
|
|
|
(a) |
|
(
|
|||||||||||||||||||||||
| Other |
|
|
|
(b) |
|
|
|||||||||||||||||||||||
| Total | $ |
|
$ |
|
$ |
|
(c) | $ |
|
$ |
(
|
||||||||||||||||||
(a)
As of March 31, 2025, the amortized cost basis of these available-for-sale investments is $
1,252
million.
(b)
Represents net pending securities sales and purchases.
(c)
All amounts pertain to APS, with the exception of $
35.1
million of other special use fund investments in equity securities relating to the Captive.
62
| December 31, 2024 | |||||||||||||||||||||||||||||
| Fair Value |
Total
Unrealized Gains |
Total
Unrealized Losses |
|||||||||||||||||||||||||||
| Investment Type: | Nuclear Decommissioning Trusts | Other Special Use Funds | Total | ||||||||||||||||||||||||||
| Equity securities | $ |
|
$ |
|
$ |
|
$ |
|
$ |
(
|
|||||||||||||||||||
| Available for sale-fixed income securities |
|
|
|
(a) |
|
(
|
|||||||||||||||||||||||
| Other |
|
|
|
(b) |
|
|
|||||||||||||||||||||||
| Total | $ |
|
$ |
|
$ |
|
(c) | $ |
|
$ |
(
|
||||||||||||||||||
(a)
As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $
1,224
million.
(b)
Represents net pending securities sales and purchases.
(c)
All amounts pertain to APS, with the exception of $
34.2
million of other special use fund investments in equity securities relating to the Captive.
The following table sets forth realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities (dollars in thousands):
| Three Months Ended March 31, | |||||||||||||||||
| Nuclear Decommissioning Trusts | Other Special Use Funds | Total | |||||||||||||||
| 2025 | |||||||||||||||||
| Realized gains | $ |
|
$ |
|
$ |
|
|||||||||||
| Realized losses | $ |
(
|
$ |
|
$ |
(
|
|||||||||||
| Proceeds from the sale of securities (a) | $ |
|
$ |
|
(b) | $ |
|
||||||||||
| 2024 | |||||||||||||||||
| Realized gains | $ |
|
$ |
|
$ |
|
|||||||||||
| Realized losses | $ |
(
|
$ |
|
$ |
(
|
|||||||||||
| Proceeds from the sale of securities (a) | $ |
|
$ |
|
$ |
|
|||||||||||
(a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding investment fees and amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
(b) All amounts pertain to APS, with the exception of $
25.3
million of other special use fund proceeds from the sale of securities relating to the Captive.
63
Fixed Income Securities Contractual Maturities
The fair value fixed income securities summarized by contractual maturities as of March 31, 2025 is as follows (dollars in thousands):
| Nuclear Decommissioning Trusts | Coal Reclamation Escrow Account | Active Union Employee Medical Account |
Captive Insurance Cell (a)
|
Total | |||||||||||||||||||||||||
| Less than one year | $ |
|
$ |
|
$ |
|
|
$ |
|
||||||||||||||||||||
| 1 year – 5 years |
|
|
|
|
|
||||||||||||||||||||||||
| 5 years – 10 years |
|
|
|
|
|
||||||||||||||||||||||||
| Greater than 10 years |
|
|
|
|
|
||||||||||||||||||||||||
| Total | $ |
|
$ |
|
$ |
|
|
$ |
|
||||||||||||||||||||
(a)
All amounts pertain to APS, with the exception of $
25.1
million of other special use fund investments in fixed income securities relating to the Captive.
15.
Changes in Accumulated Other Comprehensive Loss
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
| Pension and Other Postretirement Benefits | Derivative Instruments | Total | |||||||||||||||||||||
| Three Months Ended March 31 | |||||||||||||||||||||||
|
Balance December 31, 2024
|
$ |
(
|
$ |
|
$ |
(
|
|||||||||||||||||
|
Other comprehensive income before reclassifications
|
|
|
|
||||||||||||||||||||
|
Amounts reclassified from accumulated other comprehensive loss
|
|
(a) |
|
|
|||||||||||||||||||
|
Balance March 31, 2025
|
$ |
(
|
$ |
|
$ |
(
|
|||||||||||||||||
|
Balance December 31, 2023
|
$ |
(
|
$ |
|
$ |
(
|
|||||||||||||||||
|
Other comprehensive (loss) before reclassifications
|
|
|
|
||||||||||||||||||||
|
Amounts reclassified from accumulated other comprehensive loss
|
|
(a) |
|
|
|||||||||||||||||||
|
Balance March 31, 2024
|
$ |
(
|
$ |
|
$ |
(
|
|||||||||||||||||
(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7
64
The following table shows the changes in APS’s accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):
| Pension and Other Postretirement Benefits | |||||||||||
| Three Months Ended March 31 | |||||||||||
|
Balance December 31, 2024
|
$ |
(
|
|||||||||
|
Other comprehensive (loss) before reclassifications
|
|
||||||||||
|
Amounts reclassified from accumulated other comprehensive loss
|
|
(a) | |||||||||
|
Balance March 31, 2025
|
$ |
(
|
|||||||||
|
Balance December 31, 2023
|
$ |
(
|
|||||||||
|
Other comprehensive (loss) before reclassifications
|
|
||||||||||
|
Amounts reclassified from accumulated other comprehensive loss
|
|
(a) | |||||||||
|
Balance March 31, 2024
|
$ |
(
|
|||||||||
(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.
16.
Leases
We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2025 through 2073. Substantially all of our leasing activities relate to APS.
In 1986, APS entered into agreements with
three
separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 8 for a discussion of VIEs.
APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year, the leases have non-consecutive periods of use. APS does not operate or maintain the leased assets. APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets, APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets. The variable consideration is not included in the measurement of our lease obligation.
65
APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities. APS pays a fixed monthly capacity price for rights to use the lease assets. The agreements generally have
20
-year lease terms and provide APS with the exclusive use of the energy storage assets through the lease term. APS does not operate or maintain the energy storage facilities and has no purchase options or residual value guarantees relating to these lease assets. For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components. These leases are accounted for as operating leases, with lease terms that commenced between September 2023 and March 2025.
The following table provides information related to our lease costs (dollars in thousands):
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Operating Lease Cost - Purchased Power and Energy Storage Lease Contracts | $ |
|
$ |
|
||||||||||
| Operating Lease Cost - Land, Property, and Other Equipment |
|
|
||||||||||||
| Total Operating Lease Cost |
|
|
||||||||||||
| Variable Lease Cost (a) |
|
|
||||||||||||
| Short-term Lease Cost |
|
|
||||||||||||
| Total Lease Cost | $ |
|
$ |
|
||||||||||
(a) Primarily relates to purchased power lease contracts.
Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to purchased power and energy storage lease contracts are recorded in fuel and purchased power on the Condensed Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 6. The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease
liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheets.
66
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
| March 31, 2025 | ||||||||||||||||||||
| Year | Purchased Power and Energy Storage Lease Contracts | Land, Property and Equipment Leases | Total | |||||||||||||||||
| 2025 (remaining nine months of 2025) | $ |
|
$ |
|
$ |
|
||||||||||||||
| 2026 |
|
|
|
|||||||||||||||||
| 2027 |
|
|
|
|||||||||||||||||
| 2028 |
|
|
|
|||||||||||||||||
| 2029 |
|
|
|
|||||||||||||||||
| 2030 |
|
|
|
|||||||||||||||||
| Thereafter |
|
|
|
|||||||||||||||||
| Total lease commitments |
|
|
|
|||||||||||||||||
| Less imputed interest |
|
|
|
|||||||||||||||||
| Total lease liabilities | $ |
|
$ |
|
$ |
|
||||||||||||||
We recognize lease assets and liabilities upon lease commencement. As of March 31, 2025, we have various lease arrangements that have been executed, but have not yet commenced. We expect the total fixed consideration paid for these arrangements, which includes both lease and non-lease payments, will approximate $
14.8
billion over the terms of the agreements. These arrangements primarily relate to energy storage assets. We expect lease commencement dates ranging from April 2025 through June 2028, with lease terms expiring through June 2048. The lease commencement dates for certain arrangements have experienced delays. As a result of these delays and other events, APS has received cash proceeds from certain lessors prior to lease commencement. Proceeds received from lessors relating to energy storage Power Purchase Agreement (“PPA”) leases are accounted for as lease incentives on our Condensed Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term. For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received. See Note 6.
67
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: | $ |
|
$ |
|
||||||||||
| Right-of-use operating lease assets obtained in exchange for operating lease liabilities: | $ |
|
(a) | $ |
|
|||||||||
| March 31, 2025 | December 31, 2024 | ||||||||||
| Weighted average remaining lease term |
|
|
|||||||||
| Weighted average discount rate (b) |
|
% |
|
% | |||||||
(a)
Primarily relates to the
three
new energy storage operating lease agreements that commenced in 2025.
17.
Income Taxes
As a part of the Inflation Reduction Act of 2022 (“IRA”), a new PTC for nuclear energy produced by existing nuclear energy plants was enacted (“Nuclear PTC”), available from 2024 through 2032. The Nuclear PTC can be increased by five times if certain IRS prevailing wages rules are met. The Company continues to await guidance from the U.S. Treasury Department related to the definition of “gross receipts” from nuclear sales for purposes of the credit phase-out applicable to the Nuclear PTC. Without such guidance, the Company is unable to make a reasonable estimate of the potential benefit the Nuclear PTC may provide. As a result, no income tax benefits have been recorded related to the Nuclear PTC as of March 31, 2025.
18.
Sale of Bright Canyon Energy
On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE.
The BCE Sale was accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024.
Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a wholly-owned subsidiary of Pinnacle West.
The BCE Sale did not include a $
31
million equity bridge loan relating to BCE’s Los Alamitos project, which was paid in full by Pinnacle West on
August 4, 2023.
Other than these retained investments and the debt instrument, all BCE assets and liabilities were included in the BCE Sale and were transferred to Ameresco.
The total carrying value of net assets transferred to Ameresco as a result of the BCE Sale was $
79
million, with total consideration received by Pinnacle West of $
108
million, resulting in a total pre-tax gain of $
29
million, which was recognized between August 4, 2023 and January 12, 2024. The net assets transferred included $
41
million of liabilities that have been assumed by Ameresco. The consideration
68
received by Pinnacle West included both cash and interest-bearing promissory notes. The stages of the BCE Sale and timing of net assets transferring to Ameresco and related gain recognition are as follows:
•
The first stage of the BCE Sale was completed on August 4, 2023. In the first stage, the net assets transferred to Ameresco totaled $
44
million, which included a $
36
million construction term loan. The assets and liabilities transferred in the first stage related to the BCE Los Alamitos project and were previously primarily classified as construction work in progress and current maturities of long-term debt, respectively. A gain of $
6
million was recognized on our Consolidated Statements of Income for the year ended December 31, 2023, relating to the first stage of the BCE Sale.
•
The final stage of the BCE Sale was completed on January 12, 2024. In the final stage, the net assets transferred to Ameresco totaled $
35
million. The assets transferred in the final stage related primarily to equity method investments in the Kūpono Solar Project and other development stage projects. Our Condensed Consolidated Statements of Income for the year ended 2024, included a $
23
million gain relating to the final stage of the BCE Sale.
As of January 12, 2024, all stages of the BCE Sale have been completed. As of December 31, 2024 the interest-bearing promissory note had been paid in full.
On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $
23
million of investment tax credits from the BCE Los Alamitos project for $
21
million.
69
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes to the Condensed Consolidated Financial Statements (“Notes”) that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part 1, Item 1A of the 2024 Form 10-K and Part II, Item 1A of this report.
OVERVIEW
Business Overview
Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $27 billion.
Since 1886, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.
Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS.
APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.4 million retail customers in 11 of Arizona’s 15 counties.
APS is also the operator and co-owner of Palo Verde Generating Station (“Palo Verde”) — a primary source of electricity for the southwestern United States.
Strategic Overview
Our strategy is to create a sustainable energy future for Arizona that delivers shareholder value and shared value by serving our customers with reliable, affordable, and clean energy.
Customer-Focused
APS’s focus remains on its customers and the communities it serves. In furtherance of a customer-centric culture, APS employees have delivered an enhanced customer experience in recent years through a number of past and ongoing initiatives, such as improving the ease-of-use of APS’s automated phone system, improving the speed of answering customer calls, advancing phone advisor soft skill development through updated training curriculum, and adding 1,100-plus in-person payment locations, as well as introducing new customer payment channels. Recently, APS redesigned its customer bills with the aim of increasing personalization and helping customers better understand their energy use and ways to save. APS also implemented numerous enhancements to its website, including improving page-loading speeds, adding user-friendly dashboards, and making content more simple, relevant, and useful. APS enhanced other customer touchpoints as well, such as communications throughout outages and the online outage center in addition to continuing to communicate with customers in their preferred channels about topics that matter most to them, such as reliability, energy-efficiency, financial assistance, the environment, and programs that enable them to design their own personalized energy experience. Finally, APS continues to focus on employee learning, training, tools, and resources to ensure all employees understand their role in APS customers’ experiences.
70
Additionally, APS has implemented a variety of financial assistance programs to support customers struggling to pay their energy bills. Among these assistance programs are discounts for qualified limited-income customers, including a new tier with larger discounts for APS’s lowest income customers added in the second quarter of 2024 and other non-income-based assistance programs, such as flexible payment arrangements and emergency utility bill assistance. To ensure our most vulnerable customers are connected to these programs, we train and partner with more than one hundred community action agencies across our service territory.
Reliable
While our energy mix evolves, APS’s commitment to deliver reliable service to our customers remains.
APS is managing through significant growth in the Phoenix metropolitan area while experiencing supply chain issues similar to those experienced in other industries.
Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth, and enabling more renewable energy resources.
To prioritize reliability and meet substantial growth in customer energy needs, APS has developed a future-focused, strategic transmission plan (the “Ten-Year Transmission Plan”).
The Ten-Year Transmission Plan includes critical transmission projects that comprise the APS strategic transmission portfolio, which represent a significant upgrade to our existing transmission system.
These transmission projects will support growing energy needs, strengthen reliability, and allow for the connection of new resources.
Our advanced distribution management system allows operators to locate outages and control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid.
Wildfire safety remains a critical focus for APS and other utilities. We have increased investment in fire mitigation efforts to clear defensible space around our infrastructure, continue ongoing system upgrades, build partnerships with government entities and first responders and educate customers and communities. We also increased spend on mitigating the risk associated with trees that could cause hazards, resulting in more of these trees being removed before they could cause outages or wildfires. These programs contribute to customer reliability, responsible forest management and safe communities. With recent wildfire events in Hawaii, California, and across North America, we have been devoting and will continue to devote substantial efforts to analyzing and developing enhancements to our systems and processes to mitigate fire risk within our service territory and communities, including by hardening our infrastructure, deploying new technologies where appropriate, increasing our awareness, implementing operational changes, and enhancing our wildfire response capabilities. APS completed implementation of fire modeling software that we are utilizing to more surgically identify and calculate risk and target future system improvement investments such as fire-resistant pole wrapping, wood to steel pole conversions, and additional remote-controllable field devices like reclosers and switches. In 2024, APS began installing a system of artificial intelligence-based fire sensing cameras with the ability to detect and alert on fire ignitions. These alerts are sent both to APS and fire response dispatch centers to speed fire response in APS’s service territory regardless of the cause of the fire. APS also implemented a public safety power shutoff (“PSPS”) program on certain feeders that began in the 2024 fire season, leveraging the additional real-time analysis provided by the new modeling software, and has educated and is continuing education outreach to customers and communities that may potentially be impacted by the PSPS program. APS continues to evaluate policy and regulatory options, as well as insurance programs, to mitigate the impact of wildfire events.
71
For example, on August 14, 2024, APS filed a request with the Arizona Corporation Commission (“ACC”) for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs. APS cannot predict the outcome of this matter. See Note 6 in Part I of this quarterly report for more information.
Additionally, APS was selected by the U.S. Department of Energy’s (“DOE”) Grid Deployment Office (“GDO”) to receive up to $70 million in federal money for fire mitigation and grid infrastructure projects. This funding is part of the GDO’s Grid Resilience and Innovation Partnership Program and is contingent on APS negotiating and executing final grant agreements with GDO.
Maintaining reliability and affordability for customers is fundamental to APS’s strategy. Dispatchable natural gas generators provide energy during times when intermittent resources, such as solar and wind, are insufficient to meet customer demand. In addition to the previously added natural gas units at the modernized Ocotillo Power Plant in 2019 and efficiency improvements to gas units at the Redhawk, Sundance, and West Phoenix Power Plants in 2024, APS has contracted for two simple cycle combustion turbines (approximately 90 MW in total) at Sundance, which are expected to be in service in 2026, and eight simple cycle combustion turbines (approximately 397 MW in total) at Redhawk, which are expected to be in service in 2028. APS continues to evaluate and pursue options for reliably serving growing customer energy needs and demand.
APS went live with a new Energy Management System (“EMS”) in April 2024. APS expects the new EMS to provide a better foundation which will improve future integration of the renewable and energy storage assets into APS’s generation resource portfolio, allowing APS to maximize the flexibility of its resources and fully engage in the Western Energy Imbalance Market (“WEIM”).
APS also believes it will better position APS to participate in market opportunities that develop over the next decade.
APS’s key elements to delivering reliable power include resource and transmission planning, sufficient reserve margins, partnering with customers to manage peak demand, fire mitigation, and operational preparedness, among others. Seasonal readiness procedures at APS include inspections to ensure good material conditions and critical control system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating with federal, state, and local agencies on fire and emergency management.
Affordable
APS continues to focus on mitigating the cost pressures related to inflation and other factors, such as tariffs.
Overall inflation grew by 1.8% in Phoenix and 2.8% nationally over the twelve months ended February 2025. Although inflationary impacts to APS have slightly eased in recent months, APS remains cautious of potential price increases as a result of current and proposed tariffs, which could lead to higher costs and supply chain constraints.
APS’s customer affordability initiative includes internal opportunities, such as training and mentoring employees on identifying efficiency opportunities; maintaining an inventory to take advantage of lower pricing and avoid expediting fees; entering into long-term contracts to hedge against price volatility, which has allowed APS to mitigate against procurement spend areas such as transformers; and implementing automation technologies to enhance efficiencies and increase data-oriented decision making.
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There are also external opportunities that allow APS to deliver more affordable energy to customers, such as APS’s participation in western energy markets and programs. APS participated in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool (“SPP”). The Markets+ tariff was filed with the U.S. Federal Energy Regulatory Commission (“FERC”) on March 29, 2024 and was approved on January 16, 2025. APS is a funding party to the implementation phase of Markets+ and expects to go live in the market in 2027. In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool and is transitioning to full-binding participation as early as summer 2027. These regional efforts are driven by the objectives of reducing customer cost and improving reliability. Until the transition to Markets+, APS will continue to participate in WEIM as a tool for creating savings for APS’s customers from the real-time only, voluntary market. APS expects that its participation in WEIM and future participation in Markets+ will lower its fuel and purchased-power costs, improve situational awareness for systems operations in the Western Interconnection power grid, and improve integration of APS’s clean resources.
In terms of generation affordability, every three years, APS performs a comprehensive study, called an Integrated Resource Plan (“IRP”), to identify what resources will be necessary to safely and reliably meet the demand and energy needs of its customers over the next 15 years.
In November 2023, APS released its latest IRP, which identified forecasted customer demand and energy needs growing at an unprecedented rate.
In developing the IRP, APS considered how factors such as forecasted economic growth, impacts from weather, and new resource technology availability impact the amount and type of resources required to reliably meet customer needs.
These factors, among others, were used to develop a plan that identified a balanced mix of diverse energy generating resources to reliably serve customers’ future energy needs in the most affordable and sustainable manner possible. To help ensure competitive costs for resources procured by APS, APS regularly issues competitive bid solicitations through the all-source request for proposal (“ASRFP”) process, with the most recent ASRFPs being issued in 2022, 2023, and 2024. These ASRFPs are open to bids for all resource types, including customer-scale (behind the meter) and utility-scale (in front of the meter) resources. Through the ASRFP process, APS has found that clean resources like wind, solar, and energy storage technology, are important elements of a least cost portfolio.
During the clean energy transition, dispatchable resources will play a vital role in maintaining grid reliability by serving as a back-up to intermittent energy resources when output is insufficient to meet customer needs. Over the long term, each resource in a balanced and diverse portfolio is expected to provide complementary value and contribute to sustained delivery of reliable electric service.
In addition to managing the cost of electricity generation, APS has continued building upon existing cost management efforts, including a customer affordability initiative launched in 2019.
The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and achieving internal efficiencies.
APS continues to drive this initiative by identifying opportunities to streamline its business processes, mitigate cost increases, increase employee retention, and improve customer satisfaction.
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Clean Energy Commitment
We are committed to doing our part to build a clean and carbon-free future.
As Arizona stewards, we do what is right for the people and prosperity of Arizona.
Our vision is to create a sustainable energy future for Arizona by providing reliable, affordable, and clean energy to our customers.
We can accomplish our vision by collaborating with customers, communities, employees, policymakers, shareholders, and other stakeholders.
Our clean energy commitment is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.
APS’s clean energy commitment consists of three parts:
•
A 2050 goal to provide 100% clean, carbon-free electricity;
•
A 2030 target to achieve a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and
•
A plan to exit from coal-fired generation by 2031.
APS’s ability to successfully execute its clean energy commitment depends upon a number of important external factors, including a supportive regulatory environment, sales and customer growth, development of clean energy technologies, and continued access to capital markets, among others.
2050 Goal: 100% Clean, Carbon-Free Electricity.
Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration.
Achieving this 2050 goal will require, among other things, innovative thinking, emergent clean energy and storage technologies, upgrades and expansions to the grid, and supportive public policy.
2030 Goal: 65% Clean Energy.
APS has an energy mix that is approximately 54% clean and plans to continue to add more renewables and energy storage. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix, which includes all carbon-free resources like nuclear, renewables, and demand-side management. “Renewable” energy includes generation resources such as solar, wind, and biomass, and is measured in accordance with the ACC Renewable Energy Standard as a percentage of retail sales. This target will serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward a 100% clean, carbon-free energy mix by 2050.
2031 Goal: Exit Coal-Fired Generation.
The plan to exit coal-fired generation by 2031 will require APS to stop relying on coal-generation at Four Corners Power Plant (“Four Corners”). APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in annual carbon emissions that were 34% lower in 2024 compared to 2005. In addition, APS has ceased generating electricity at the Cholla Power Plant (“Cholla”) in March 2025, in accordance with federal regulations and due to increasing costs that have made the plant uneconomical to operate. On April 8, 2025, President Trump issued coal-related executive orders aimed at increasing domestic energy production. APS is monitoring the executive orders and related regulatory actions.
In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners as early as fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership.
Under
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seasonal operation, one generating unit would be shut down during seasons when electricity demand is reduced, such as the winter and spring.
The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages.
As of the date of this report,
APS has elected not to begin seasonal operation due to market conditions.
Renewables.
APS’s IRP identifies a diverse mix of resources adequate to maintain grid reliability while serving increasing future customer energy needs.
Our IRP shows that renewable and clean resources are an important part of a reliable, cost effective portfolio. APS seeks market-based pricing of procured resources through regular solicitation of project bids using its competitive ASRFP process.
APS has a diverse portfolio of existing and planned resources, including solar, wind, energy storage, nuclear, geothermal, biomass and biogas, that supports our commitment to clean energy. This commitment is already strengthened by Palo Verde, one of the nation’s largest carbon-free, clean energy resources, which provides the foundation for reliable and affordable service for APS customers. APS’s longer-term clean energy strategy includes pursuing the right mix of purchased power contracts for new resources, procurement of new resources to be owned by APS, and the ongoing development of distributed energy resources. Maintaining a balanced and diverse portfolio of resources will ensure continued reliable service to our customers in the most affordable manner possible.
APS uses competitive ASRFPs to pursue market-priced resources that meet its system needs and offer the best value for customers.
APS selects projects based on cost, ability to meet system requirements and commercial viability, taking into consideration timing and likelihood of successful contracting and development.
Under current market conditions, APS must aggressively contract for resources that can withstand supply chain and other geopolitical pressures.
Guided by IRP-established timelines and quantities, APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the ASRFP process.
Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection to the electric grid.
On June 30, 2023, APS issued an ASRFP (the “2023 ASRFP”) pursuant to which
APS procured nearly 7,300 MW of new resources to be in service from 2026 to 2028.
On November 20, 2024, APS issued an ASRFP (the “2024 ASRFP”) seeking 2,000 MW of resources. APS is seeking projects that can reach commercial operation beginning June 1, 2028 through June 1, 2030 but will consider projects that may achieve commercial operation as early as 2026. Additionally, APS is interested in projects that require longer planning, permitting, and construction and can be commercially operational after June 1, 2030. Bids for the 2024 ASRFP were due on February 5, 2025.
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The following table summarizes the resources in APS’s renewable energy portfolio that are in operation, planned or under development as of the date of this report. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting, and interconnection of the projects to the electric grid.
|
Net Capacity in Operation
(MW) |
Net Capacity Planned / Under
Development (MW) |
|||||||||||||
| Total APS Owned: Solar | 417 | 168 | ||||||||||||
| PPAs Renewables: | ||||||||||||||
| Solar | 1,425 | 2,481 | ||||||||||||
| Wind | 853 | 500 | ||||||||||||
| Geothermal | 10 | — | ||||||||||||
| Biomass | 14 | — | ||||||||||||
| Biogas | 3 | — | ||||||||||||
| Total PPAs | 2,305 | 2,981 | ||||||||||||
| Total Distributed Energy: Solar (a) | 1,749 | 66 | (b) | |||||||||||
| Total Renewable Portfolio | 4,471 | 3,215 | ||||||||||||
(a) Includes rooftop solar facilities owned by third parties. DG is produced in direct current and is converted to alternating current for reporting purposes.
(b) Applications received by APS that are not yet installed and online.
Energy Storage.
APS deploys a number of advanced technologies on its system, including energy storage.
Energy storage provides capacity, improves power quality, can be utilized for system regulation and, in certain circumstances, be used to defer certain traditional infrastructure investments.
Energy storage also aids in integrating renewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset.
APS is utilizing grid-scale energy storage projects to meet customer reliability requirements, increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid.
The following table summarizes the resources in APS’s energy storage portfolio that are in operation, planned or under development as of the date of this report. Agreements for the development and completion of future resources are subject to various conditions.
| Net Capacity in Operation (MW) | Net Capacity Planned / Under Development (MW) | ||||||||||||||||
| APS Owned Energy Storage | 201 | (a) | 150 | ||||||||||||||
| PPAs Energy Storage | 1,541 | 3,951 | |||||||||||||||
| Customer-Sited Energy Storage | 79 | 42 | |||||||||||||||
| Total Energy Storage Portfolio | 1,821 | 4,143 | |||||||||||||||
(a) Includes 0.3 MW of APS-owned customer-sited energy storage.
Palo Verde
.
Palo Verde, one of the nation’s largest carbon-free, clean energy resources, will continue to be a foundational part of APS’s resource portfolio.
Palo Verde is not just the cornerstone of our current clean energy mix; it also is a significant provider of clean energy to the southwestern United States.
The plant is a critical asset to the Southwest, generating more than 32 million MWh annually –
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enough power for roughly 3.4 million households, or approximately 8.5 million people.
Its continued operation is important to a carbon-free and clean energy future for Arizona and the region, a
s a reliable, continuous, affordable resource and as a large contributor to the local economy.
Developing Clean Energy Technologies
New Nuclear Generation
APS, along with other Arizona electric utilities, is exploring additional nuclear generation to provide around-the-clock carbon-free energy to meet rising energy demands in Arizona. APS has been monitoring emerging nuclear technologies, such as small modular nuclear reactors (“SMRs”). SMRs are typically designed to generate 300 MW or less of energy per unit compared to, for example, the 1,400 MW per unit generated at Palo Verde. The utilities have applied for a grant from the DOE to begin preliminary exploration of a potential site for additional nuclear energy for Arizona. The grant could support a three-year site selection process and possible preparation of an early site permit application to United States Nuclear Regulatory Commission (“NRC”).
Electric Vehicles and Demand Side Management (“DSM”)
As a part of the Arizona statewide transportation electrification plan (“TE Plan”) adopted in 2021, the ACC approved a target of 450,000 light-duty electric vehicles (“EVs”) in APS’s service territory by 2030. APS’s Take Charge AZ (“TCAZ”) program has helped to deploy Level 2 EV charging stations on customer properties for fleet, public, and workplace EV charging. As of March 31, 2025, APS has installed 829 energized Level 2 charging ports at 197 customer locations. Additionally, APS has energized direct current fast charging stations that are owned and operated by APS at five locations in Arizona: Sedona, Prescott, Globe, Show Low, and Payson. Effective December 12, 2023, the TCAZ program was discontinued by the ACC. As part of that decision, APS was permitted to complete certain projects that were in process as of December 12, 2023.
Additionally, as part of APS’s DSM Implementation Plan, APS launched the EV Charging Demand Management Pilot to proactively address the growing electric demand from charging as EVs become more widely adopted. The EV programs in the DSM Implementation Plan include APS SmartCharge (an EV data gathering program), Fleet Advisory Services, and a $100 rebate to homebuilders for new homes to be built EV-ready with 240V receptacle. APS previously offered a $250 residential rebate to customers that purchased a qualifying home Level 2 charger. Effective December 12, 2023, APS discontinued this rebate per the ACC decision. See the discussion above. APS has also filed, and the ACC has approved, an application for a new Bring-Your-Own-Device (“BYOD”) Battery Pilot Plan of Administration as required by Decision No. 79293. This plan allows APS to work with residential customers to enable APS to dispatch participating batteries and use them to provide demand response capacity to the grid. The BYOD program will be incorporated into future DSM Implementation Plan filings.
APS filed its 2024 DSM Implementation Plan on November 30, 2023. The 2024 DSM Implementation Plan includes APS’s 2024 TE Plan and, among other things, proposes two new programs that were initially proposed in the 2023 DSM Implementation Plan: an expanded residential EV Managed Charging program and a Commercial EV Make-Ready Program. On April 26, 2024, APS filed an amended 2024 DSM Implementation Plan. The amended 2024 DSM Implementation Plan includes an updated budget of $90.9 million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation,
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and the withdrawal of tranches two and three of the residential battery pilot. The amended 2024 DSM Implementation Plan is still pending ACC review and approval. APS does not intend to file a 2025 DSM Implementation Plan, pending ACC review of the amended 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.
Carbon Capture
Carbon Capture Utilization and Storage (“CCUS”) technologies can isolate CO
2
and either sequester it permanently in geologic formations or convert it for use in products.
Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen.
CCUS technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions.
These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired.
APS will continue to monitor this emerging technology.
Sustainability Practices
In 2020, in support of our clean energy commitment, we created a Sustainability Department at Pinnacle West responsible for integrating responsible business practices into the everyday work of the Company.
In 2024, we leveraged an external consultant and leveraged input from employees, large customers, limited-income advocates, economic development groups, tribes, nonprofits, environmental non-governmental organizations, residential customers, and other stakeholders to identify and assess the sustainability issues that matter most. In total, 15 Priority Sustainability Issues (“PSIs”) were identified and prioritized. The top five issues that were prioritized by stakeholders are as follows: energy affordability, electric reliability, clean energy and decarbonization, workforce development, and climate resilience and adaptation. Understanding the sustainability priorities of internal and external stakeholders can help companies improve performance, identify risks and opportunities, and refine sustainability strategy.
Artificial Intelligence
To address the rapid advancement of artificial intelligence technology risks and opportunities, APS has developed a cross functional governance structure with leadership and experts from our information technology, cybersecurity, human resources, ethics, supply chain, legal, and nuclear generation teams.
This cross functional structure assesses the opportunities and risks in alignment with enterprise strategy to ensure compliance with data security and reliability requirements as well as our Code of Ethical Conduct, while observing market trends in this rapidly evolving area.
Regulatory Overview
APS expects to file an application with the ACC for its next general rate case mid-year 2025 and is continuing to evaluate the timing of such filing.
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2022 Retail Rate Case
APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates.
On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”) in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”). The 2022 Rate Case ROO recommended, among other things, (i) a $523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36%, (v) 12 months of post-test year plant and the inclusion of the Four Corners Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the Other Post-Employment Benefits liability, and (ix) no disallowances on APS’s coal contracts.
The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $1.9 million of Renewable Energy Adjustment Charge (“REAC”) in the adjustor rather than base rates, (iii) a partial transfer of $27.1 million of Lost Fixed Cost Recovery Mechanism (“LFCR”) funds to base rates, and (iv) the adoption of an increase in the annual Power Supply Adjustor (“PSA”) cap to $0.006/kWh.
On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an ASRFP, and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.
The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill.
The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.
Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association (“AriSEIA”), Solar Energy Industries Association (“SEIA”), and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. A limited rehearing was held October 28 through November 1, 2024. Following the limited rehearing, an Administrative Law Judge issued a ROO (the “Limited Rehearing ROO”) on December 3, 2024. The Limited Rehearing ROO recommended affirming the GAC as just and reasonable
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and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers. On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing. The Commission has taken no action on these requests. In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.
Regulatory Lag Docket
On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates. On December 3, 2024, the ACC approved a policy statement regarding formula rate plans. The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases. On March 28, 2025, the Residential Utility Consumer Office filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. APS cannot predict the outcome of this matter.
Cholla ACC Deferral Request
On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of Cholla Units 1 and 3. This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, coal combustion residuals (“CCR”) corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. APS cannot predict the outcome of this matter.
Fire Mitigation
On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs. APS cannot predict the outcome of this matter.
See Note 6 for information regarding additional regulatory matters.
Captive Insurance Cell
Pinnacle West is the primary beneficiary of
a protected cell captive insurance cell (the “Captive”). The Captive provides insurance coverage to Pinnacle West and our subsidiaries that supplements third-party insurance policies.
The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. The Captive policies exclude nuclear liability at Palo Verde. See Note 10.
The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments.
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Inflation Reduction Act of 2022
The Inflation Reduction Act of 2022 (“IRA”) significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage.
Key provisions that are relevant to APS’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a Production Tax Credit (
“
PTC
”
) in lieu of the Investment Tax Credit (
“
ITC
”
) beginning in 2022; (ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023; (iii) introduction of technology neutral clean energy ITCs and PTCs beginning in 2025; and (iv) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032.
The Internal Revenue Service and U.S. Treasury Department have issued guidance related to various provisions of the IRA that have enabled APS to claim credits related to its solar and energy storage investments.
The Company continues to await regulations and other guidance, including with respect to the nuclear PTC, which will provide additional details and clarifications regarding how the Company may be able to claim IRA tax credits. See Note 17 for more information.
The potential for enactment of federal tax reform legislation, including modification or repeal of some or all of the IRA tax provisions, has increased. Such changes may impact the availability of future potential tax benefits from the IRA and could impact the Company’s effective tax rate, cash taxes paid and other financial results such as earnings per share, gross revenues, and cash flows. We cannot predict the timing or extent of such tax-related developments which, absent appropriate regulatory treatment, may have a negative impact on our financial results.
Financial Strength and Flexibility
We believe that Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures are anticipated to be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Other Subsidiaries
PNW Power
On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary Bright Canyon Energy Corporation (“BCE”) to Ameresco (the “BCE Sale”).
The transaction was accounted for as the sale of a business and closed in multiple stages.
T
he final closing of the BCE Sale was completed on January 12, 2024. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to Pinnacle West Power, LLC (“PNW Power”), a wholly-owned subsidiary of Pinnacle West.
PNW Power’s investments include TransCanyon, a 50/50 joint venture that was formed in 2014 with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. TransCanyon is pursuing independent electric transmission opportunities within the 11 U.S. states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates. The DOE’s GDO selected TransCanyon to enter into capacity contract negotiations for up to 25% of the Cross-
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Tie 500-kilovolt transmission line (“Cross-Tie”) as part of the Transmission Facilitation Program. The agreement was executed on June 12, 2024. The proposed Cross-Tie project includes a 214-mile transmission line connecting Utah and Nevada that is intended to help improve grid reliability and relieve congestion on other transmission lines.
PNW Power’s investments also include minority ownership positions in two wind farms operated by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms.
Clear Creek achieved commercial operation in May 2020; however, in the fourth quarter of 2022, PNW Power’s equity method investment was fully impaired.
Nobles 2 achieved commercial operation in December 2020.
Both wind farms deliver power under long-term PPAs.
PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.
El Dorado Investment Company (“El Dorado”)
El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. In particular, El Dorado has committed to and/or holds the following:
•
$25 million investment in the Energy Impact Partners fund, of which approximately $19.1 million has been funded as of March 31, 2025. Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.
•
$25 million investment in AZ-VC (formerly invisionAZ Fund), of which approximately $14.3 million has been funded as of March 31, 2025. AZ-VC is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately-held early stage and emerging growth technology companies and businesses primarily based in Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona.
•
$7.5 million investment in Westly Seed Fund, of which approximately $1.2 million has been funded as of March 31, 2025. Westly Seed Fund is focused on supporting entrepreneurs involved in the energy, mobility, building, and industrial sectors.
•
Equity investment in SAI Advanced Power Solutions (“SAI”), a private corporation that manufactures electrical switchgear equipment used by data centers. El Dorado accounts for this investment under the equity method, with a March 31, 2025 investment carrying value of $12.1 million. SAI has seen an increased demand for their customized switchgear products. El Dorado has no funding commitments to SAI.
The remainder of these investment commitments will be contributed by El Dorado as each investment fund selects and makes investments.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
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Electric Operating Revenues.
For the years 2022 through 2024, retail electric revenues averaged approximately 92% of our total operating revenues.
Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms.
Our revenues are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand, and prices.
Actual and Projected Customer and Sales Growth.
Retail customers in APS’s service territory increased 2.3% for the period ended March 31, 2025, compared with the prior-year period. For the three years through 2024, APS’s customer growth averaged 2.1% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2025 and the average annual growth to be in the range of 1.5% to 2.5% through 2027 based on anticipated steady population growth in Arizona during that period.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 2.1% for the period ended March 31, 2025, compared with the prior-year period. While steady customer growth was somewhat offset by weaker usage among residential customers, energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong sales to commercial and industrial customers and the continued ramp-up of new data center and large manufacturing customers. As extra high load factor customers, such as data centers and large manufacturers, have continued to grow as a proportion of our business, we have updated our procedures with respect to estimates of unbilled revenues for our customer classes. As a result, we have made an adjustment in the first quarter of 2025 to recalibrate accrued unbilled revenues, offsetting year-to-date sales growth by 1.9%. Even with this offset to sales growth in the first quarter, we do not anticipate any change to our expected range of sales growth for the full year 2025.
For the three years through 2024, annual retail electricity sales growth averaged 3.2%, adjusted to exclude the effects of weather variations. Due to the expected growth of several data centers and large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 4.0% to 6.0% for 2025 and that average annual growth will be in the range of 4.0% to 6.0% through 2027, including the effects of customer conservation, energy efficiency, and distributed renewable generation initiatives, but excluding the effects of weather variations. These projected sales growth ranges include the impacts of several data centers and large manufacturing facilities, which are expected to contribute to 2025 growth in the range of 3.0% to 5.0% and to average annual growth in the range of 3.0% to 5.0% through 2027.
Longer term, APS has been preparing for and can serve significant load growth from residential and business customers. On top of these existing growth trends, APS is also now receiving unprecedented incremental requests for service from extra high load factor customers (over 25 MW) with very high energy demands that persist virtually around-the-clock. These incremental requests for service by extra high load factor customers far exceed available generation and transmission resource capacity in the Southwest region for the foreseeable future. In April 2023, APS notified prospective extra high load factor customers without existing commitments from APS that it is not able to commit at this time to future extra large projects of over 25 MW. Because of the high growth in demand for such projects, APS has developed a prioritization queue that identifies and prioritizes projects while maintaining system reliability and affordability for existing APS customers. APS is exploring available options for securing sufficient electric generation and transmission to meet these projections of future customer needs.
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Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, slower ramp-up of and/or fewer large data centers and manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs and growth in DG, responses to retail price changes, changes in regulatory standards, and impacts of new and existing laws and regulations, including environmental laws and regulations. Based on past experience, a 1% variation in our annual residential and small commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $24 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $6 million.
Weather.
In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.
Our experience indicates that typical variations from normal weather can result in increases and decreases in annual net income of up to $20 million. However, since 2020, extreme weather events, such as record-setting summer heat and decreased annual precipitation in our service territory, have resulted in increases in annual net income that are more than historically typical, on average.
Fuel and Purchased Power Costs.
Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses
.
Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and DSM related expenses (which are mostly offset by the same amount of operating revenues) and other factors.
Depreciation and Amortization Expenses.
Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and increases in intangible assets and changes in depreciation and amortization rates.
See “Liquidity and Capital Resources” below for information regarding the planned additions to our facilities.
Pension and Other Postretirement Non-Service Credits, Net
.
Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions.
The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates.
We review these assumptions on an annual basis and adjust them, as necessary. See Note 7.
Property Taxes.
Taxes other than income taxes consist primarily of property taxes, which are affected by changes in plant balances related to new investments and improvements to existing facilities, the value of property in service and under construction, assessment ratios, and tax rates.
The average property tax rate in Arizona for APS, which owns essentially all of our property, was 9.7% of the assessed value for 2024, 10.0% for 2023, and 10.2% for 2022.
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Income Taxes
.
Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions, certain credits and non-taxable items, such as allowance for funds used during construction (“AFUDC”). In addition, income taxes may also be affected by the settlement of issues with taxing authorities.
Interest Expense.
Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. See Note 5 for further details. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.
An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.
We stop accruing AFUDC on a project when it is placed into service.
RESULTS OF OPERATIONS
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.
Operating Results – Three-month period ended March 31, 2025, compared with three-month period ended March 31, 2024.
Our consolidated net loss attributable to common shareholders for the three months ended
March 31, 2025, was $5 million, compared with consolidated net income attributable to common shareholders of $17 million for the prior-year period. The results reflect a decrease of approximately $22 million, primarily as a result of higher operations and maintenance expense, higher depreciation and amortization expense mostly due to increased plant and intangible assets, lower pension and other postretirement non-service credits, lower other income due to the gain on the sale of BCE recognized in prior year, and higher interest charges. These negative factors were partially offset by the favorable impacts of new customer rates, a gain from a non-utility equity investment by El Dorado, lower income taxes due to lower pretax income and higher tax benefits related to employee benefits, and higher transmission and LFCR revenue.
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The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated (dollars in millions):
| Pinnacle West Consolidated | APS Consolidated | ||||||||||||||||||||||||||||||||||
| Three Months Ended March 31, | Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||
| 2025 | 2024 |
Net
Change |
2025 | 2024 |
Net
Change |
||||||||||||||||||||||||||||||
| Operating revenues | $ | 1,032 | $ | 952 | $ | 80 | $ | 1,032 | $ | 952 | $ | 80 | |||||||||||||||||||||||
| Fuel and purchased power expense | (380) | (358) | (22) | (380) | (358) | (22) | |||||||||||||||||||||||||||||
| Operating revenues less fuel and purchased power expenses (a) | 652 | 594 | 58 | 652 | 594 | 58 | |||||||||||||||||||||||||||||
| Operations and maintenance | (300) | (258) | (42) | (297) | (254) | (43) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (235) | (210) | (25) | (235) | (210) | (25) | |||||||||||||||||||||||||||||
| Taxes other than income taxes | (59) | (59) | — | (59) | (59) | — | |||||||||||||||||||||||||||||
| Pension and other postretirement non-service credits, net | 3 | 12 | (9) | 3 | 12 | (9) | |||||||||||||||||||||||||||||
| Allowance for equity funds used during construction | 13 | 10 | 3 | 13 | 10 | 3 | |||||||||||||||||||||||||||||
| Other income and expenses, net | 14 | 23 | (9) | 3 | 4 | (1) | |||||||||||||||||||||||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (95) | (87) | (8) | (79) | (74) | (5) | |||||||||||||||||||||||||||||
| Income taxes | 6 | (4) | 10 | 3 | (4) | 7 | |||||||||||||||||||||||||||||
| Less income related to noncontrolling interests | (4) | (4) | — | (4) | (4) | — | |||||||||||||||||||||||||||||
|
Net Income (Loss) Attributable to Common Shareholders
|
$ | (5) | $ | 17 | $ | (22) | $ | — | $ | 15 | $ | (15) | |||||||||||||||||||||||
(a) Operating revenues less fuel and purchased power expenses is a non-GAAP financial measure. As reconciled in the table above, this amount is derived by the difference between the GAAP financial statement line item Operating revenues less the GAAP financial statement line item Fuel and purchased power expense as presented on the Condensed Consolidated Statements of Income.
Operating revenues, less fuel and purchased power expense is used by Pinnacle West to assess whether customer revenues adequately cover fuel and purchased power costs. This metric is not defined by GAAP and may differ from similar measures used by other companies. This measure is not a substitute for operating income under GAAP.
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The following relates to Pinnacle West’s consolidated results for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024:
Operating revenues less fuel and purchased power expenses.
Operating revenues less fuel and purchased power expenses were $58 million higher for the three months ended March 31, 2025, compared with the prior-year period. The following table summarizes the major components of this change (dollars in millions):
| Increase (Decrease) | |||||||||||||||||
|
Operating
revenues |
Fuel and
purchased power expenses |
Net change | |||||||||||||||
|
Impact of new rates from the 2022 Rate Case, effective March 8, 2024 (Note 6)
|
$ | 46 | $ | — | $ | 46 | |||||||||||
| Higher retail revenues due to changes in customer growth partially offset by the impacts of energy efficiency and related pricing | 5 | 4 | 1 | ||||||||||||||
| Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs | 2 | 2 | — | ||||||||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | 14 | 17 | (3) | ||||||||||||||
|
Higher transmission revenues (Note 6)
|
6 | — | 6 | ||||||||||||||
|
LFCR revenue (Note 6)
|
4 | — | 4 | ||||||||||||||
| Miscellaneous items, net | 3 | (1) | 4 | ||||||||||||||
| Total | $ | 80 | $ | 22 | $ | 58 | |||||||||||
Operations and maintenance
. Operations and maintenance expenses increased $42 million for the three months ended March 31, 2025, compared with the prior-year period primarily due to:
|
•
an increase of $17 million related to non-nuclear generation costs, primarily due to higher planned outage;
|
||
|
•
an increase of $13 million related to information technology costs;
|
||
|
•
an increase of $6 million related to transmission, distribution, and customer service costs;
|
||
|
•
an increase of $4 million related to corporate resource costs; and
|
||
|
•
an increase of $2 million for other miscellaneous factors.
|
||
Depreciation and amortization.
Depreciation and amortization expenses were $25 million higher for the three months ended March 31, 2025, compared to the prior-year period primarily due to increased plant in service and intangible assets.
Pension and other postretirement non-service credits, net.
Pension and other postretirement non-service credits, net were $9 million lower for the three months ended March 31, 2025, compared to the prior-year period primarily due to prior-service credits becoming fully amortized as of January 31, 2025. See Note 7.
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Interest charges, net of allowance for borrowed funds and equity funds used during construction.
Interest charges, net of allowance for funds used during construction, were $5 million higher for the three months ended March 31, 2025, compared to the prior-year period, primarily due to higher debt balances higher allowance for equity funds.
Other income and expenses, net.
Other income and expenses, net were $9 million lower for the three months ended March 31, 2025, compared to the prior-year period, primarily due to the gain on the sale of BCE recognized during the first quarter of 2024 (see Note 18) and lower PSA interest income, partially offset by investment gains in El Dorado. The difference between APS’s and Pinnacle West’s other income and expenses, net, is primarily related to Pinnacle West’s gain on the sale of BCE and the gain in investment in El Dorado.
Income taxes.
Income taxes were $10 million lower for the three months ended March 31, 2025, compared with the prior-year period, primarily due to lower pre-tax income and higher tax benefits related to employee benefits.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order does not allow APS to pay common dividends if the payment would reduce its common equity ratio below 40%. Per the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. As of March 31, 2025, APS’s common equity ratio, as defined, was 52%. Its total shareholder equity was approximately $8.3 billion, and total capitalization, as calculated pursuant to the ACC order, was approximately $15.9 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $6.4 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.
Dividends to Pinnacle West from APS are also dependent on a number of factors including, among others, APS’s financial condition and free cash flow, the sources of which vary from quarter-to-quarter due in part to the seasonal nature of electricity demand. APS’s sources of cash include cash from operations and external sources of liquidity, including long- and short-term external debt financing such as commercial paper, term loan and its revolving credit facility. Cash from operations is dependent upon, among other things, the rates APS may charge and the timeliness of recovering costs incurred through its rates and adjustor recovery mechanisms. APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West. On December 17, 2024, the ACC issued a financing order approving a limit on yearly equity infusions equal to 2.5% of
APS’s total ass
ets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.
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Pinnacle West and APS maintain committed revolving credit facilities that enhance liquidity and provide credit support for accessing commercial paper markets. These credit facilities mature in 2029. See Note 5.
Pinnacle West has an at-the-market equity distribution program (the “ATM Program”) under which Pinnacle West may offer and sell Pinnacle West common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors. As of March 31, 2025, approximately $800 million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreements in effect as of March 31, 2025. Pinnacle West also has forward sale agreements from an equity offering in February 2024 in effect as of March 31, 2025.
See “Financing Cash Flows and Liquidity—Equity Offerings” below and Note 12 for more information.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating, investing and financing activities (dollars in millions):
Pinnacle West Consolidated
| Three Months Ended March 31, | |||||||||||||||||
| 2025 | 2024 | Net Change | |||||||||||||||
|
Net cash flow provided by operating activities
|
$ | 402 | $ | 347 | $ | 55 | |||||||||||
|
Net cash flow used for investing activities
|
(586) | (424) | (162) | ||||||||||||||
|
Net cash flow provided by financing activities
|
190 | 82 | 108 | ||||||||||||||
|
Net increase in cash and cash equivalents
|
$ | 6 | $ | 5 | $ | 1 | |||||||||||
APS
| Three Months Ended March 31, | |||||||||||||||||
| 2025 | 2024 | Net Change | |||||||||||||||
|
Net cash flow provided by operating activities
|
$ | 409 | $ | 366 | $ | 43 | |||||||||||
|
Net cash flow used for investing activities
|
(583) | (462) | (121) | ||||||||||||||
|
Net cash flow provided by financing activities
|
179 | 101 | 78 | ||||||||||||||
|
Net increase in cash and cash equivalents
|
$ | 5 | $ | 5 | $ | — | |||||||||||
Operating Cash Flows
Three-month period ended March 31, 2025, compared with three-month period ended March 31, 2024.
Pinnacle West’s consolidated net cash provided by operating activities was $402 million in 2025 compared to $347 million in 2024, an increase of $55 million in net cash provided, primarily due to $84 million higher cash receipts from electric revenues, $32 million lower income taxes and other taxes paid; partially offset by $37 million of changes in working capital, $11 million higher fuel and purchased power costs, and $10 million higher payments for operations and maintenance costs.
The difference between
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APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to less income tax refunds at APS when compared to Pinnacle West and other changes in working capital.
Retirement plans and other postretirement benefits.
Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. Under ERISA, the qualified pension plan was estimated to be 100% funded as of January 1, 2025, and was 113% funded as of January 1, 2024. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The expected minimum required cash contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary cash contributions in 2025, 2026 or 2027. Regarding contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2025 and do not expect to make any contributions in 2025, 2026 or 2027. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 99% funded as of December 31, 2024 , and our postretirement benefit plans were 195% funded, as measured by GAAP at December 31, 2024. See Note 7 for additional details.
Investing Cash Flows
Three-month period ended March 31, 2025, compared with three-month period ended March 31, 2024.
Pinnacle West’s consolidated net cash used for investing activities was $586 million in 2025 compared to $424 million in 2024, an increase of $162 million primarily related to $123 million of increased capital expenditures, net of contributions in aid of construction, and $39 million of proceeds from the BCE Sale received in 2024. The increase in capital expenditures during the first quarter of 2025 reflects various additions and improvements to APS’s clean resources. See “Capital Expenditures” for additional details. The difference between APS’s and Pinnacle West’s net cash used for investing activities primarily relates to the BCE Sale. See Note 18.
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Capital Expenditures.
The following table summarizes the estimated capital expenditures for the next three years (dollars in millions):
Capital Expenditures
|
Estimated for the Year Ended
December 31, |
|||||||||||||||||
| 2025 | 2026 | 2027 | |||||||||||||||
| APS | |||||||||||||||||
| Generation: | |||||||||||||||||
| Clean: | |||||||||||||||||
| Nuclear Generation | $ | 150 | $ | 165 | $ | 185 | |||||||||||
| Renewables and Energy Storage Systems (“ESS”) | 335 | 165 | 430 | ||||||||||||||
| Other Generation (a) | 420 | 540 | 335 | ||||||||||||||
| Distribution | 665 | 670 | 675 | ||||||||||||||
| Transmission | 450 | 675 | 750 | ||||||||||||||
| Other | 380 | 335 | 275 | ||||||||||||||
| Total APS | $ | 2,400 | $ | 2,550 | $ | 2,650 | |||||||||||
(a)
Includes gas generation and environmental projects.
The table above does not include capital expenditures related to PNW Power projects.
Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS, as well as additions and improvements to existing fossil fuel plants. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures are expected to be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Financing Cash Flows and Liquidity
Three-month period ended March 31, 2025, compared with three-month period ended March 31, 2024.
Pinnacle West’s consolidated net cash provided by financing activities was $190 million in 2025 compared to $82 million in 2024, an increase of $108 million in net cash provided primarily due to a net increase in short-term borrowings.
APS’s consolidated net cash provided by financing activities was $179 million in 2025 compared to $101 million in 2024, an increase of $78 million in net cash provided primarily due to a net increase in short-term borrowings.
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Significant Financing Activities.
On April 23, 2025, the Pinnacle West Board of Directors declared a dividend of $0.895 per share of common stock, payable on June 2, 2025, to shareholders of record on May 5, 2025.
Available Credit Facilities
.
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 5 for more information on available credit facilities.
Equity Offerings
.
Pinnacle West entered into certain equity forward sale agreements in February 2024 and has an ATM Program under which Pinnacle West may offer and sell Pinnacle West common stock and enter into equity forward sale agreements from time to time, subject to market conditions and other factors. See Note 12. The following table summarizes the activity relating to these forward sale agreements and the ATM Program as of March 31, 2025 (in thousands, except share amounts and price per share):
| As of March 31, 2025 | |||||||||||||||||
| February 2024 Forward Sale Agreements | November 2024 ATM Forward Sale Agreement | March 2025 ATM Forward Sale Agreement | |||||||||||||||
| Initial Price | |||||||||||||||||
| Number of Shares | 11,240,601 | 552,833 | 544,959 | ||||||||||||||
| Forward Sales Price Per Share (a) | $ | 64.51 | $ | 89.73 | $ | 90.83 | |||||||||||
| Aggregate Value (in thousands) | $ | 725,131 | $ | 49,606 | $ | 49,499 | |||||||||||
| Settlements | |||||||||||||||||
| Date | 12/23/2024 | ||||||||||||||||
| Number of Shares Settled (b) | 5,377,115 | — | — | ||||||||||||||
| Forward Sales Price Upon Settlement | $ | 64.17 | $ | — | $ | — | |||||||||||
| Net Proceeds (in thousands) (c) | $ | 345,049 | $ | — | $ | — | |||||||||||
(a) Subject to certain adjustments.
(b) Physical delivery.
(c) Any proceeds are recorded in equity.
Other Financing Matters.
See Note 9 for information related to the change in our margin and collateral accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. As of March 31, 2025, the ratio was approximately 59% for Pinnacle West and 50% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.
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Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change covenant for credit facility borrowings.
The ACC has authorized a limit on yearly equity infusions into APS equal to 2.5% of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points. See Note 5 for additional long-term debt provisions and further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of April 28, 2025, are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a potential downward revision to our credit ratings.
| Moody’s | Standard & Poor’s | Fitch | |||||||||||||||
| Pinnacle West | |||||||||||||||||
| Corporate credit rating | Baa2 | BBB+ | BBB | ||||||||||||||
| Senior unsecured | Baa2 | BBB | BBB | ||||||||||||||
| Commercial paper | P-2 | A-2 | F3 | ||||||||||||||
| Outlook | Stable | Stable | Stable | ||||||||||||||
| APS | |||||||||||||||||
| Corporate credit rating | Baa1 | BBB+ | BBB+ | ||||||||||||||
| Senior unsecured | Baa1 | BBB+ | A- | ||||||||||||||
| Commercial paper | P-2 | A-2 | F2 | ||||||||||||||
| Outlook | Stable | Stable | Stable | ||||||||||||||
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Contractual Obligations
Pinnacle West has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows:
•
Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates as of March 31, 2025. See Note 5.
•
Pinnacle West and APS maintain committed revolving credit facilities. See Note 5 for short-term debt details.
•
Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 6 and 10. Purchase obligations include capital expenditures and other obligations. See Note 10. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 16.
•
APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 6 and 10.
•
APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 8.
•
APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation. See Note 10.
•
Pinnacle West’s equity forward sale agreements, which may be settled by Pinnacle West with common stock or cash. See Note 12.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies and estimates since our 2024 Form 10-K. See “Critical Accounting Policies and Estimates” in Item 7 of the 2024 Form 10-K for further details about our critical accounting policies and estimates.
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OTHER ACCOUNTING MATTERS
See Note 3 for information on the following new accounting standards that are pending adoption:
•
ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, effective for us on December 31, 2025.
•
ASU 2024-03, Income Statement Reporting: Expense Disaggregation Disclosures, effective for us on December 31, 2027.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trusts, other special use funds and benefit plan assets.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Notes 13 and 14), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning, coal reclamation, and benefit plan costs are recovered in regulated electricity prices.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions):
| Three Months Ended March 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Balance at beginning of period | $ | (42) | $ | (120) | |||||||
| Decrease (increase) in regulatory asset | 128 | (35) | |||||||||
| Balance at end of period | $ | 86 | $ | (155) | |||||||
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The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) as of March 31, 2025, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements” in Item 8 of our 2024 Form 10-K and Note 13 for more discussion of our valuation methods.
| Source of Fair Value | 2025 | 2026 | 2027 | 2028 | 2029 |
Total
Fair Value |
||||||||||||||||||||||||||||||||
| Observable prices provided by other external sources | $ | 65 | $ | 40 | $ | 5 | $ | (1) | $ | — | $ | 109 | ||||||||||||||||||||||||||
| Prices based on unobservable inputs | (14) | (9) | — | — | — | (23) | ||||||||||||||||||||||||||||||||
| Total by maturity | $ | 51 | $ | 31 | $ | 5 | $ | (1) | $ | — | $ | 86 | ||||||||||||||||||||||||||
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets (dollars in millions):
|
March 31, 2025
Gain (Loss)
|
December 31, 2024
Gain (Loss)
|
||||||||||||||||||||||
| Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||||||||||
| Mark-to-market changes reported in: | |||||||||||||||||||||||
| Regulatory asset (liability) (a) | |||||||||||||||||||||||
| Electricity | $ | 8 | $ | (8) | $ | 3 | $ | (3) | |||||||||||||||
| Natural gas | 90 | (90) | 75 | (75) | |||||||||||||||||||
| Total | $ | 98 | $ | (98) | $ | 78 | $ | (78) | |||||||||||||||
(a)
These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 9 for a discussion of our credit valuation adjustment policy.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Key Financial Drivers” and “Market and Credit Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.
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ITEM 4. CONTROLS AND PROCEDURES
(a)
Disclosure Controls and Procedures
The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2025. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of APS’s disclosure controls and procedures as of March 31, 2025. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.
(b)
Changes in Internal Control Over Financial Reporting
The term “internal control over financial reporting” (defined in Exchange Act Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended March 31, 2025, that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.
PART II
—
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 of the 2024 Form 10-K with regard to pending or threatened litigation and other matters.
See Note 6 for ACC and FERC-related matters.
See Note 10 for information regarding environmental matters, Superfund-related matters and other disputes.
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ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A — Risk Factors in the 2024 Form 10-K
,
which could materially affect the business, financial condition, cash flows or future results of Pinnacle West and APS. The risks described in the 2024 Form 10-K are not the only risks facing Pinnacle West and APS. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition, cash flows and/or operating results of Pinnacle West and APS.
ITEM 5. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the fiscal quarter ended March 31, 2025,
none of our directors or executive officers adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” as each term is defined in Item 408 of Regulation S-K.
ITEM 6.
EXHIBITS
(a)
Exhibits
| Exhibit No. | Registrant(s) | Description |
Previously Filed as Exhibit
(a)
|
Date Filed | ||||||||||||||||||||||
| 3.1 | Pinnacle West | 3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | 8/7/2008 | |||||||||||||||||||||||
| 3.2 | Pinnacle West | 3.1 to Pinnacle West/APS February 25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473 | 2/25/2020 | |||||||||||||||||||||||
| 3.3 | APS | Articles of Incorporation, restated as of May 25, 1988 | 4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473 | 9/29/1993 | ||||||||||||||||||||||
| 3.4 | APS | 3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473 | 5/22/2012 | |||||||||||||||||||||||
| 3.5 | APS | 3.4 to Pinnacle West/APS December 31, 2008 Form 10-K Report, File Nos. 1-8962 and 1-4473 | 2/20/2009 | |||||||||||||||||||||||
| 31.1 | Pinnacle West | |||||||||||||||||||||||||
| 31.2 | Pinnacle West | |||||||||||||||||||||||||
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| 31.3 | APS | |||||||||||||||||||||||||
| 31.4 | APS | |||||||||||||||||||||||||
|
32.1
(b)
|
Pinnacle West | |||||||||||||||||||||||||
|
32.2
(b)
|
APS | |||||||||||||||||||||||||
| 101.INS |
Pinnacle West
APS |
Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document. | ||||||||||||||||||||||||
| 101.SCH |
Pinnacle West
APS |
Inline XBRL Taxonomy Extension Schema Document | ||||||||||||||||||||||||
| 101.CAL |
Pinnacle West
APS |
Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||||||||||||||||||||||
| 101.LAB |
Pinnacle West
APS |
Inline XBRL Taxonomy Extension Label Linkbase Document | ||||||||||||||||||||||||
| 101.PRE |
Pinnacle West
APS |
Inline XBRL Taxonomy Extension Presentation Linkbase Document | ||||||||||||||||||||||||
| 101.DEF |
Pinnacle West
APS |
Inline XBRL Taxonomy Definition Linkbase Document | ||||||||||||||||||||||||
| 104 |
Pinnacle West
APS |
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||||||||||||||||||||||
_______________________________
(a)
Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
(b)
Furnished herewith as an exhibit.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| PINNACLE WEST CAPITAL CORPORATION | ||||||||||||||
| (Registrant) | ||||||||||||||
| Dated: | May 1, 2025 | By: | /s/ Andrew Cooper | |||||||||||
| Andrew Cooper | ||||||||||||||
| Senior Vice President and | ||||||||||||||
| Chief Financial Officer | ||||||||||||||
| (Principal Financial Officer and | ||||||||||||||
| Officer Duly Authorized to sign this Report) | ||||||||||||||
| ARIZONA PUBLIC SERVICE COMPANY | ||||||||||||||
| (Registrant) | ||||||||||||||
| Dated: | May 1, 2025 | By: |
/s/ Andrew Cooper
|
|||||||||||
| Andrew Cooper | ||||||||||||||
| Senior Vice President and | ||||||||||||||
| Chief Financial Officer | ||||||||||||||
| (Principal Financial Officer and | ||||||||||||||
| Officer Duly Authorized to sign this Report) | ||||||||||||||
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TABLE OF CONTENTS
Part I Financial InformationprintItem 1. Financial StatementsprintItem 2. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 3. Quantitative and Qualitative Disclosures About Market RiskprintItem 4. Controls and ProceduresprintPart II Other InformationprintPart IIprintItem 1. Legal ProceedingsprintItem 1A. Risk FactorsprintItem 5. Other InformationprintItem 6. Exhibitsprint