ARIZONA PUBLIC SERVICE CO

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, and 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 VIE related to the Captive. The unaudited Condensed Consolidated Financial Statements for APS include the accounts of APS and the Palo Verde VIEs. In September 2025, APS purchasedtwo of thethree leased interests, resulting in the termination of the related lease agreements and discontinuation of VIE consolidation for those leases. As of September 30, 2026, one Palo Verde VIE lease arrangement remains active. See Note 9 for further discussion on Pinnacle West’s VIEs and APS’s remaining VIE. 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. Our accounting records are maintained in accordance with 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.

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 2025 Form 10-K.

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

The following table summarizes supplemental APS cash flow information (dollars in thousands):

(a) Represents a payable from APS to Pinnacle West as of September 30, 2026.

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.

For information on our reportable business segment’s revenues, significant expenses, net income (loss), assets, and other reportable segment items, see the APS Condensed Consolidated Statements of Income, APS Condensed Consolidated Balance Sheets, and APS Condensed Consolidated Statements of Cash Flows.

The following table reconciles our reportable segment’s revenues, significant expenses, and net income (loss) to the Pinnacle West consolidated amounts (dollars in millions):

The following table reconciles our reportable segment’s assets to the Pinnacle West consolidated amount (dollars in millions):

3. New Accounting Standards

ASU 2024-03, Income Statement Reporting: 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 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 Consolidated 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. We are currently evaluating the transition method and date of adoption we will elect for this new standard.

ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software: Targeted Improvements to the Accounting for Internal-Use Software

In September 2025, a new accounting standard was issued that modernizes the accounting for internal-use software costs by removing references to prescriptive and sequential development stages of a project and replacing them with new criteria used in determining when to start capitalizing software costs. Under the new guidance, capitalization begins when management authorizes and commits to funding the software project and it is probable the project will be completed and used as intended. When determining if a project is probable of being completed, entities must evaluate whether significant development uncertainty exists, such as unresolved technological innovations or unproven features. The new guidance also clarifies that capitalized internal-use software costs are subject to the existing property, plant, and equipment disclosure requirements.

The standard will become effective for us on January 1, 2028, with early adoption permitted. Entities may adopt the standard using one of the following transition methods: a prospective approach, a retrospective approach, or a modified transition approach that considers in-process projects at the date of adoption. We are currently evaluating the impacts on our financial statements of adopting this new standard and the transition method and date of adoption we will elect. The adoption of this guidance may impact our timing and scope of software costs eligible for capitalization, and may also impact our disclosures relating to software.

ASU 2025-09, Derivatives and Hedging: Hedge Accounting Improvements

In November 2025, a new accounting standard was issued which clarifies certain aspects of the hedge accounting guidance. The new standard is intended to better align hedge accounting with the economics of an entity’s risk management activities, and provides entities the ability to apply hedge accounting to an expanded population of economic hedges of forecasted transactions. The standard will become effective for us on January 1, 2027, applied on a prospective basis. Early adoption is permitted. We expect to adopt this guidance on January 1, 2027. We are not currently applying hedge accounting, and do not expect the adoption of this guidance will have a material impact on our financial statements.

ASU 2025-10, Government Grants: Accounting for Government Grants Received by Business Entities

In December 2025, a new accounting standard was issued establishing authoritative GAAP guidance on the accounting for government grants received by business entities. Prior to the issuance of this new standard, GAAP did not include guidance relating to government grants received by business entities. The new standard is intended to eliminate diversity in practice and improve the financial reporting and consistency across business entities for government grants. The new standard defines government grants and includes recognition, measurement, presentation, and disclosure requirements. The new standard includes guidance pertaining to both government grants received relating to an asset and government grants received relating to income. The guidance includes recognition thresholds based on the probability of compliance with grant conditions and receipt of the grant, among other accounting requirements. Disclosure requirements include the nature and amounts of government grants received, the conditions attached to the grants, and accounting policies applied.

The new standard will become effective for us on January 1, 2029, with early adoption permitted. Entities may adopt the standard using various transition methods, including a modified prospective approach, a modified retrospective approach, or a retrospective approach to all government grants. We are currently evaluating the impacts on our financial statements of adopting this new standard, as well as the date we will adopt this guidance and the transition method we will elect.

ASU 2026-02, Environmental Credits and Environmental Credit Obligations

In May 2026, a new accounting standard was issued establishing comprehensive accounting requirements for environmental credits and environmental credit obligations. Prior to the issuance of this new standard, GAAP did not include specific guidance relating to these types of instruments and activities. The new standard defines environmental credits and environmental credit obligations and provides a framework for recognition, measurement, presentation, and disclosure.

Entities will be required to capitalize or expense an environmental credit based on the entity’s planned use. Environmental credits probable of being used for regulatory compliance purposes, sold, or used in nonreciprocal transfers will qualify to be recognized as assets. Generally, environmental credit assets will initially be measured at cost, with certain exceptions. Environmental credits held solely for voluntary initiatives are required to be expensed as costs are incurred. For environmental credit obligations, entities will be required to recognize liabilities that arise from existing or enacted laws, statutes, or ordinances to prevent, control, reduce, or remove emissions or other pollution that may be settled with environmental credits. Liabilities will be measured assuming the reporting date is the end of the compliance period. The liabilities will initially be measured at a cost associated with the credit used to settle the obligation, and may be funded or unfunded obligations. The standard requires gross presentation of credits and obligations and expanded disclosures regarding credit types, intended use, estimates, and financial statement impacts.

The new standard will become effective for us on January 1, 2028, with early adoption permitted. Entities must adopt the standard using a retrospective approach through a cumulative-effect adjustment to the opening balance of retained earnings as of the beginning of the annual reporting period of adoption, without recasting any financial statement information before the period of adoption. We are currently evaluating the impacts on our financial statements of adopting this new standard, as well as the date we will adopt this guidance. As required, we will adopt the standard using the retrospective transition approach.

4. Revenue

Sources of Revenue

The following table provides detail of Pinnacle West’s consolidated revenues disaggregated by revenue sources (dollars in thousands):

Retail Electric Service

All of Pinnacle West’s retail electric revenues are generated by APS. Retail electric revenues are generated by the sale of electricity to our customers within the regulated 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.

In October 2026, APS executed a DPC to provide future retail electric services to TSMC Arizona Corporation (“TSMC Arizona”). See Note 7. APS expects to submit the DPC to the ACC for regulatory approval in 2026. APS cannot predict the outcome of this matter. The DPC had no impact on revenues recognized during the three or nine months ended September 30, 2026.

Wholesale Energy Sales and Transmission Services for Others

All of Pinnacle West’s revenues from wholesale energy sales and transmission services for others are generated by APS and represent energy and transmission sales to wholesale customers. These activities consist of managing fuel and purchased power risks and transmission needs 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 FERC.

In the electricity business, some contracts to purchase electricity 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 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 and nine months ended September 30, 2026 were $1,965 million and $4,540 million, respectively, and for the three and nine months ended September 30, 2025 were $1,822 million and $4,186 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 and nine months ended September 30, 2026 our revenues that do not qualify as revenue from contracts with customers were $8 million and $38 million, respectively, and for the three and nine months ended September 30, 2025 were negative $1 million and $26 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 7 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 continuously 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):

5. 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 (“Nuclear PTC”) was enacted, 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.

The Company claimed benefits for the Nuclear PTC on its 2025 and 2024 tax returns of $39.6 million and $33.4 million, respectively, using a revenue requirement methodology to determine its gross receipts from nuclear sales. Additionally, utilizing this same methodology, the Company estimates that the 2026 tax credit will be $35-$40 million. These benefits include the five times multiplier for complying with IRS prevailing wage rules. However, due to the continued lack of IRS guidance, management believes that there remains uncertainty as to whether the IRS will ultimately agree with the Company’s gross receipts methodology. As a result, as of September 30, 2026, the Company’s Nuclear PTC benefits are recorded as uncertain tax positions and the Company continues to not recognize any income tax benefits related to the Nuclear PTC.

The Company's 2022 - 2024 federal tax returns are currently under exam by the IRS. The IRS has indicated that the focus of this exam will be on Inflation Reduction Act tax credits, including the Nuclear PTC. At this time, we are unable to predict the outcome of this exam and whether it will have a material impact on our financial position, results of operations, or cash flows.

6. 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.

Pinnacle West

As of September 30, 2026, Pinnacle West had a $300 million revolving credit facility that matures on February 18, 2031. Pinnacle West has the option to increase the amount of the facility by $100 million to a total of $400 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. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $300 million commercial paper program, bank borrowings, and issuances of letters of credit. As of September 30, 2026, Pinnacle West hadno outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $99 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on September 30, 2026 was 4.05%.

Pinnacle West has an outstanding 364-day $175 million term loan facility that matures on December 3, 2026. Borrowings under the facility bear interest at SOFR plus 0.80% per annum. On December 3, 2025, Pinnacle West drew the full amount of $175 million.

On June 5, 2026, Pinnacle West issued $500 million of 4.65% senior unsecured notes that mature June 1, 2029. The net proceeds from the issuance were used to repay $350 million of floating rate senior unsecured notes that were due to mature June 10, 2026, to pay down $50 million of short-term indebtedness consisting of commercial paper, and for general corporate purposes.

APS

As of September 30, 2026, APS had a $1.7 billion revolving credit facility that matures on February 18, 2031. APS has the option to increase the amount of the facility by $400 million to a total of $2.1 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. The facility is available to support APS’s general corporate purposes, including support for APS’s $1.5 billion commercial paper program, bank borrowings, and issuances of letters of credit. As of September 30, 2026, APS hadno outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $165 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on September 30, 2026 was 4.05%.

On March 10, 2026, APS issued $600 million of 5.10% senior unsecured notes that mature March 15, 2036. The net proceeds from the issuances were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.

On August 13, 2026, APS issued $600 million of 6.25% senior unsecured notes that mature August 15, 2056 and reopened its 5.50% senior unsecured notes that mature September 1, 2035, issuing an additional $100 million of such notes. The net proceeds from the issuances were used to repay the $250 million senior unsecured notes that matured September 15, 2026 and to repay $450 million of short-term indebtedness consisting of commercial paper and for general corporate purposes.

On June 5, 2026, Pinnacle West contributed $100 million into APS in the form of an equity infusion. APS used this contribution to pay down short-term indebtedness consisting of commercial paper.

On July 31, 2026, APS submitted an application to the ACC requesting to increase the long-term debt limit from $9.5 billion to $12 billion. APS cannot predict the outcome of this matter.

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 11 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):

7. Regulatory Matters

ACC General Retail Rate Cases

2025 Rate Case

On June 13, 2025, APS filed an application with the ACC (the “2025 Rate Case”) seeking a net base rate increase of $579.5 million, which represents a 13.99% net increase. The requested net increase addresses a total base revenue deficiency of $662.4 million, offset by proposed adjustor transfers of cost recovery to base rates.

The 2025 Rate Case application includes the following proposals:

•a test year comprised of the 12-month period ended on December 31, 2024, including certain pro forma adjustments;

•12 months of post-test year plant placed into service from January 1, 2025 through December 31, 2025;

•an original cost rate base of $12.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•a rate of $0.043881 per kWh for the portion of APS’s base rates attributable to fuel and purchased power costs;

•adjustments to rate designs, including direct assignment of costs, to reduce cross-subsidization by certain customer classes;

•modification of cost allocation methodologies based on customer growth to ensure customers causing new production costs are covering those costs through rates, along with corresponding changes to adjustor mechanisms, such as for fuel and purchased power;

•implementation of a FRAM to assist with reducing regulatory lag and allow for rate gradualism;

•elimination of the LFCR following the first annual adjustment pursuant to the FRAM; and

•modification to the SRB due to the FRAM proposal.

On March 2 and March 18, 2026, the ACC Staff, Residential Utility Consumer Office (“RUCO”), and other intervenors filed their initial written testimony with the ACC. ACC Staff’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $525.2 million total base revenue increase, (ii) a 9.55% to 9.80% return on equity, (iii) a 0.20% return on the increment of fair value, and (iv)12 months of post-test year plant. RUCO’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $200.2 to $278.1 million total base revenue increase, (ii) a 9.00% to 9.20% return on equity, (iii) a 0.0% return on the increment of fair value, and (iv)0 to 12 months of post-test year plant.

On April 3, 2026, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony are as follows:

•a total revenue requirement increase of $694.2 million, or a net revenue requirement increase of $611.3 million after adjustor transfers;

•maintaining a return on equity request of 10.7%;

•reducing the return on the increment of fair value from 1.0% to 0.9%;

•maintaining a post-test year plant request of 12 months and updating the impacted projects, including Ironwood solar and Sundance; and

•an integrated set of FRAM modifications that are intended to be evaluated together:

◦allowing for an earnings test “deadband” range of +/-40 basis points to APS’s authorized return before an adjustment to the FRAM would be required;

◦limiting projected plant tosix months;

◦elimination of the SRB and TEAM following the first annual adjustment pursuant to the FRAM;

◦retention of the 120-day review and challenge period; and

◦elimination of the interim rate reset by accepting ACC approval prior to implementation (subject to an automatic reversion provision).

On May 1, 2026, ACC Staff, RUCO, and other intervenors filed their surrebuttal testimonies with the ACC. The ACC Staff adjusted their initial recommendation to a $506.5 million total base revenue increase and additional revisions to APS’s FRAM proposal, including the continued recommendation for an earnings test “deadband” range of +/-50 basis points.

On May 11, 2026, APS filed its rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies. APS’s rejoinder testimony included adjustments to the proposed schedule for the annual FRAM filing and a reduction of the total revenue requirement increase to $691.6 million, representing a revenue requirement increase, net of adjustor transfers, of $608.7 million. All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.

APS requested that the increase become effective in the second half of 2026. The hearing concluded on July 7, 2026. APS and other parties filed their Initial Post-Hearing Briefs and Reply Briefs on August 27, 2026 and September 11, 2026, respectively. Although APS anticipates that the 2025 Rate Case will be resolved before the end of this year, APS cannot predict the outcome of its request nor when the 2025 Rate Case will be decided by the ACC.

2022 Rate Case

On October 28, 2022, APS filed an application with the ACC (the “2022 Rate Case”) for an increase in retail base rates, and on January 25, 2024, an Administrative Law Judge issued a ROO, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

On February 22, 2024, the ACC approved the 2022 Rate Case ROO with certain amendments 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 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 Coal Community Transition 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 ACC’s December 17, 2024 decision on the rehearing. The ACC has taken no action on these requests. In addition, each of these parties subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. On February 25, 2026, parties provided oral arguments before the Court of Appeals. On June 16, 2026, the Arizona Court of Appeals found that the GAC and related increases for residential solar customers were imposed by the ACC without adequate notice or opportunity to be heard. Following motions for reconsideration filed by APS and the Commission, the Court of

Appeals denied those motions on October 29, 2026. APS now plans to file a petition for review with the Arizona Supreme Court. APS cannot predict the outcome of these proceedings, but does not expect the outcome will have a material impact on APS’ financial position, results of operations, or cash flows.

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, RUCO, the Arizona Large Customer Group (“ALCG”), and an individual customer filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. On June 13, 2025, the lawsuit challenging the ACC’s formula rate policy was dismissed by the Superior Court of Maricopa County. Following the dismissal, the plaintiffs filed an appeal with the Arizona Court of Appeals as well as a Petition for Special Action with the Arizona Supreme Court. The Supreme Court declined to exercise jurisdiction on the Petition for Special Action. The plaintiffs also filed a Petition for Special Action with the Arizona Court of Appeals, which has accepted jurisdiction to determine whether the case should be remanded back to the Superior Court for expedited consideration of the merits. On November 21, 2025, the Arizona Court of Appeals ruled that the issue should be remanded back to the Superior Court to determine whether the ACC’s formula rate policy must go through a formal rulemaking process. In response, APS, the ACC, and several other Arizona utility companies filed petitions for review of the Court of Appeals decision with the Arizona Supreme Court. That petition was denied on May 8, 2026, which returned the litigation to the Superior Court of Maricopa County for further proceedings on the merits of whether the ACC’s issuance of the formula rate policy statement complied with the Arizona Administrative Procedure Act. Subsequent to that remand, the Superior Court granted a motion on August 28, 2026 to stay the proceedings pending the outcome of appellate litigation in the Arizona Court of Appeals addressing challenges to the UNS Gas Inc. Annual Rate Adjustment Mechanism, which is premised on similar grounds as the Superior Court litigation. Thereafter, on September 28, 2026, RUCO filed a petition for another special action with the Arizona Supreme Court seeking to reverse the Superior Court’s stay and enjoin further implementation of retail formula rates in Arizona pursuant to the ACC’s policy statement. APS cannot predict the outcome of this matter or the impact (if any) it may have on other proceedings.

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 Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case and “2025 Rate Case” above for proposed modifications to adjustment mechanisms in the 2025 Rate Case.

Renewable Energy Standard

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. 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 afive-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 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, excluding any funding offsets. On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $92.7 million. On July 1, 2025, APS filed its 2026 RES Implementation Plan and proposed a budget of approximately $110.1 million, excluding any funding offsets. 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 2025. The proposed plan also notifies the ACC that continued evaluation and approval of the pending 2024 and 2025 RES Implementation Plans is no longer necessary. On February 4, 2026, the ACC approved APS’s 2026 RES Implementation Plan.

On April 22, 2025, the ACC approved APS’s request to refund uncommitted DSMAC and RES surcharge funds of approximately $9 million and $43 million, respectively, with final amounts subject to adjustment dependent upon billed usage. Refunds were issued during July and August of 2025 totaling $7.6 million for DSMAC and $44.2 million for RES.

On July 1, 2026, APS filed its 2027 RES Implementation Plan and proposed a budget of approximately $120.9 million, excluding any funding offsets. The budget for the Implementation Plan consists of funding for existing contractual commitments and other regulatory obligations arising from RES compliance. Additionally, APS is seeking approval of the renewable generation waiver until further order by the ACC to eliminate APS’s requirement to own and retire renewable energy credits to demonstrate compliance with the RES standard. APS cannot predict the outcome of this matter.

As discussed below in “Energy Modernization Plan,” on August 14, 2025, the ACC voted to send a full repeal of the RES rules to the Secretary of State for publication. See below for more information.

APS has a Green Power Partners Program that allows customers to pay a specified price to receive a contracted amount of green power in addition to their normal rate in order to support those customers in meeting their individual sustainability goals. On June 28, 2024, APS filed an application for approval of modifications to the Green Power Partners Program and requested a renewable energy credit waiver granting APS the ability to sell its renewable energy credits rather than simply banking and retiring them for compliance purposes and thereby allowing the revenue generated from such sales to flow back directly to APS customers through rate adjustments. On February 4, 2026, the ACC approved APS’s proposed changes to the Green Power Partners Program, including permitting the sale of renewable energy credits and modifications to pricing structures for participating customers.

On September 4, 2026, APS filed an application with the ACC requesting that APS issue a credit of approximately $33.6 million to customers through a one-time Renewable Energy Adjustment Charge. The credit is primarily based on revenue from the Green Power Partners Program sales. On October 7, 2026, the ACC approved this credit.

Demand Side Management Adjustor Charge

The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan at least every odd year 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 November 30, 2022 and May 31 2023, APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million, and an amended 2023 DSM Implementation Plan, respectively. 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 Implementation Plan. On April 26, 2024 and June 20, 2025, APS filed amendments to the 2024 DSM Implementation Plan. The Second Amended 2024 DSM Implementation Plan, compared to the initially filed plan, supported an updated budget of $90.9 million, which reflected (i) removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, (ii) exclusion of the proposed tranches two and three of the Residential Battery Pilot, and inclusion of the newly approved Bring-Your-Own-Device Battery (“BYOD”) Pilot described below, and (iii) an update on the performance incentive calculation. On May 16, 2025, APS filed a request with the ACC to extend the deadline to file its 2026 DSM Implementation Plan until 120 days after the ACC acts on its Second Amended 2024 DSM Implementation Plan. On July 9, 2025, the ACC approved APS’s extension request. On December 3, 2025, the ACC voted to reduce the budget of the DSM program to $40 million and discontinue several programs and customer rebates while promoting the expansion of Virtual Power Plant programs. On April 7, 2026, APS filed an updated DSM and Transportation Electrification Plan consistent with recent ACC orders.

On August 30, 2024, APS filed an application for a new 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.

As discussed above under “Renewable Energy Standard,” APS refunded uncommitted DSMAC funds during July and August 2025 totaling $7.6 million for DSMAC.

As discussed below in “Energy Modernization Plan,” on September 17, 2025, the ACC voted to send a full repeal of the EES rules to the Secretary of State for publication. See below for more information.

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 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-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 (liability) (dollars in thousands):

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 per kWh. 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.

On November 26, 2025, APS filed its PSA rate for the PSA year beginning February 1, 2026. The overall PSA rate of $0.016977 per kWh consists of a forward component of $0.012457 per kWh, a historical component of $0.00452 per kWh, andno transition component. This overall PSA rate is an increase of $0.003 per kWh over the prior approved rate, and it is below the annual PSA rate increase cap of $0.006 per kWh. The rate became effective the first billing cycle of February 2026.

On October 2, 2026, APS filed a Notice of Delayed Annual PSA Reset filing. This filing informed the ACC that APS will file its annual PSA update after the ACC’s decision in the 2025 Rate Case. APS understands that the ACC may issue a final decision in its pending 2025 Rate Case in December of 2026. If so, APS anticipates filing its Annual PSA Reset for the 2027 PSA Year in January of 2027, recognizing that this may result in delayed rate adjustments for the 2027 PSA Year. In the meantime, APS will maintain the currently authorized PSA rate.

Transmission Rates, Transmission Cost Adjustor, 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, 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 rates 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.

Effective June 1, 2025, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $119.0 million for the 12-month period beginning June 1, 2025, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $4.6 million and retail customer rates would have increased by approximately $114.4 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 $88.3 million, resulting in increases to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2025.

Effective June 1, 2026, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $13.1 million for the 12-month period beginning June 1, 2026, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $1.5 million and retail customer rates would have increased by approximately $11.6 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 increased by $20.6 million, resulting in increases to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2026.

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 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 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.

On July 31, 2025, APS filed its 2025 annual LFCR adjustment, requesting that effective

November 1, 2025, the annual LFCR recovery amount be increased to $60.1 million (a $10.5 million increase from previous levels). On November 21, 2025, the ACC approved the 2025 annual LFCR adjustment, with new rates effective in the first billing cycle of December 2025.

On July 31, 2026, APS filed its 2026 annual LFCR adjustment, requesting that effective November 1, 2026, the annual LFCR recovery amount be increased to $72.5 million (a $12.4 million increase from previous levels). APS cannot predict the outcome of this matter.

Tax Expense Adjustor Mechanism

The TEAM helps address potential federal income tax reform and enables 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 ACC Decision No. 79293.

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, $57.3 million of which has been collected as of September 30, 2026, 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.

Solar Export Price

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 DG 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 May 1, 2024, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $0.06857 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 May 1, 2025, APS filed an application for revisions to the RCP. This application would decrease the RCP price to $0.06171 per kWh, reflecting a 10% annual reduction, to become effective September 1, 2025. On August 14, 2025, the ACC approved the RCP as filed.

On May 1, 2026, APS filed an application for revisions to the RCP. This application requests a decrease to the RCP price to $0.05554 per kWh, reflecting a 10% annual reduction, to become effective September 1, 2026. On August 12, 2026, 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 DG Docket. Following various conferences, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes at this time along with closure of the docket. On October 6, 2025, the ACC administratively closed the general docket, and APS expects no additional action in this matter.

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review the Arizona Administrative Code related to Resource Planning, RES and EES. Subsequently, on January 9, 2024, the ACC approved the opening of new dockets to begin rulemaking processes for EES and RES. The ACC voted to send to the Secretary of State full repeals of the RES and EES rules on August 14, 2025 and September 17, 2025, respectively, for publication and to begin the public rulemaking process.

On March 4, 2026, the ACC approved the ROO to repeal the RES Rules and directed Staff to create and file with the Office of the Attorney General a Notice of Final Rulemaking package. Both the Sierra Club and the State of Arizona Attorney General’s Office filed a request for rehearing of Decision No. 81677 on March 30, 2026. On April 2, 2026, a Notice of Final Rulemaking and Final Economic Impact Statement was delivered to the Attorney General’s Office. In response to this Notice, the Attorney General’s Office notified the ACC that it was rejecting the rulemaking implementing the RES repeal for failure to follow required procedural steps. On October 7, 2026, the ACC’s Hearing Division issued a ROO to amend Decision No. 81677 to clarify that the repeal of the RES is within the ACC’s constitutional authority, eliminating the need for review by the Attorney General's Office. The ROO also orders ACC Staff to file the Notice of Final Rulemaking directly with the Office of the Secretary of State. The ACC has yet to rule on this ROO and APS cannot predict the outcome of this matter.

On July 8, 2026, the ACC repealed the EES Rules effective immediately, instructing ACC Staff to submit a Notice of Final Rulemaking to the Arizona Secretary of State. The State of Arizona Attorney General’s Office filed a request for rehearing of Decision No. 82007 on August 3, 2026. APS cannot predict the outcome of this matter.

Integrated Resource Plan

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 November 1, 2023, APS filed its 2023 IRP and 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 system resource adequacy as well as analysis of impacts from western market participation and planned resource requirements in the next IRP, which is due to be filed on October 30, 2026.

On October 30, 2026, APS submitted its 2026 IRP to the ACC for acknowledgement. Stakeholder comments on the IRP are due January 28, 2027. APS cannot predict the outcome of this matter.

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 residential customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). In addition, APS temporarily pauses shutting off residential customers for nonpayment in locations where the following day’s temperature is forecasted to be 95°F or higher or 32°F or lower according to the U.S. National Weather Service website. Since the Annual Disconnection Moratorium began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts. Customers with past due balances of $75 or greater as the Annual Disconnection Moratorium nears its end are automatically placed on six-month payment arrangements prior to beginning the disconnection process.

Cholla Power Plant

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s if 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, 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.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and decommissioning and site remediation costs of Cholla Units 1 and 3 related to the cessation of coal-burning operations at Cholla in April 2025. This order would authorize APS to defer for future recovery in rates the expenses necessary to cease operating coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. On July 8, 2025, APS withdrew its deferral application, requesting that the costs that would have been covered in the deferral order request instead be addressed in the 2025 Rate Case.

APS ceased coal-burning operations at Cholla in March 2025 and formally retired Cholla Units 1 and 3 on April 30, 2025. Upon the cessation of coal-fired operations, APS had approximately $81 million of remaining net-book value associated with Units 1 and 3 plant assets. APS is currently recovering in rates a return on the net-book value of its interest in Cholla and associated depreciation costs. In the 2025 Rate Case, APS has requested recovery in rates of the ongoing environmental remediation and CCR closure costs associated with Cholla and any remaining unrecovered plant costs. The 2025 Rate Case also includes a request for an ongoing deferral order relating to anticipated increased environmental remediation costs relating to Cholla that may be incurred after the 2025 Rate Case proceeding. APS cannot predict the outcome of this matter.

For Cholla Unit 2, APS has been allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, totaling $20.1 million as of September 30, 2026, in addition to a return on its investment. 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 July 2, 2026, APS announced plans to converttwo units at Cholla to natural gas, adding approximately 380 MW of gas-fired generation. The plan is subject to change pending the comparison to other generation sources that APS is considering in its evaluation of the 2025 ASRFP. The plan contemplates that construction on the gas conversion would begin in 2028 with targeted in-service dates beginning in 2029.

On August 31, 2026, APS filed with the ACC a notice of its intention to convert Cholla Units 1 and 3 to natural gas and application to amend the certificate of environmental compatibility for Cholla Unit 3 to authorize conversion to natural gas. 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. 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, $16.6 million as of September 30, 2026, 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 was allowed recovery of the Navajo coal reclamation regulatory asset, which is fully recovered as of August 2026. The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial statements.

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. On June 18, 2025, the ACC denied APS’s request and recommended that wildfire related expenses be recovered in APS’s 2025 Rate Case.

On May 12, 2025, the Arizona governor signed into law a bill that requires Arizona electric utilities to develop and seek approval for wildfire mitigation plans and defines the standard of care with respect to wildfire-related claims by reference to such plans.

On February 1, 2026, APS submitted its 2026 Comprehensive Wildfire Mitigation Plan for approval to the Department of Forestry and Fire Management, which approved APS’s plan on May 7, 2026. On October 6, 2026, APS filed its approved 2026 Comprehensive Wildfire Mitigation Plan with the ACC.

Direct Pricing Contract

On October 16, 2026, APS signed a DPC with TSMC Arizona. APS expects to submit the DPC to the ACC for regulatory approval in 2026. APS cannot predict the outcome of this matter.

Pursuant to the DPC, APS has agreed to provide service ramping to approximately 1.88 gigawatts to power TSMC Arizona’s semiconductor fabs/advanced packaging facilities for an initial term of 25 years. The DPC includes various contractual provisions to support the development of resources for APS to meet the load demand, including upfront payments for credit support and various forms of liquid and non-liquid collateral beginning on January 1, 2027. The exact amount and forms of collateral will vary throughout the term of the DPC depending on various factors, including the in-service dates of the resources developed to support TSMC Arizona.

Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in thousands):

(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/loss and result in lower future revenues. The 2022 Rate Case decision allows for the full return on the pension asset in rate base. See Note 8 for further discussion.

(b)This asset relates to the purchase of previously leased interest in Palo Verde Unit 2. See Note 9.

(c)See “Cost Recovery Mechanisms” discussion above.

(d)Subject to a carrying charge.

(e)Collected in retail rates.

(f)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.”

The detail of regulatory liabilities is as follows (dollars in thousands):

(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)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(c)See Note 8.

(d)See “Cost Recovery Mechanisms” discussion above.

(e)Subject to a carrying charge.

8. 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. Our plan assets are measured at fair value as of the measurement date.

The following table provides detail of the plans’ net periodic benefit costs (credits) and the portion of these costs charged to expense or credited to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The expected minimum required cash contributions for the pension plan arezero for the next three years. However, while we do not expect to make a voluntary contribution in 2026, we are evaluating whether to make voluntary contributions in 2027 and 2028. The amount of voluntary contributions will be determined as we continue to evaluate and assess our ongoing contribution strategy. We have not made any contributions to our other postretirement benefit plan in 2026 and do not expect to make contributions in 2026, 2027 or 2028.

9. 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.

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 11 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 commercial and mutual 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 a decrease in Pinnacle West’s net income of $3.2 million and an increase in Pinnacle West’s net income of $1.2 million for the three and nine months ended September 30, 2026, respectively. For the three and nine months ended September 30, 2025, consolidation of the Captive resulted in increases to Pinnacle West’s net income of $1.2 million and $3.6 million, respectively. Amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts the Pinnacle West Condensed Consolidated Statements of Income operations and maintenance expense, other income, and other expense line items.

Pinnacle West’s Condensed Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025 include $42 million and $40 million, respectively, of assets relating to the Captive, substantially all of which are reported within the other special use funds line item. See Notes 14 and 15 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 VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. In September 2025, APS purchasedtwo of thethree leased interests, thetwo related lease agreements were terminated and VIE consolidation treatment was discontinued for thosetwo leases. Due to the purchases, APS now owns these previously leased interests, providing APS a total ownership interest in Palo Verde Unit 2 of 23.9%. APS’s remaining leased interest in Palo Verde Unit 2 is approximately 5.2%. See Note 12 in the 2025 Form 10-K for additional details regarding thetwo purchased leases.

As of September 30, 2026, one VIE lease arrangement remains in effect. The VIE lease agreement that was not subject to the purchase agreements is not impacted by the purchase transactions, and APS continues to consolidate this lessor VIE.

Under the current remaining lease, in effect through 2033, APS will be required to make payments relating to the lease in total of approximately $9 million annually for the period 2026 through 2033. At the end of the lease period, APS will have the option to purchase the leased asset at its fair market value, extend the lease for up totwo years, or return the asset to the lessor. The lease terms give APS the ability to utilize the asset for a significant portion of the asset’s economic life, and therefore provide APS with the power to direct activities of the VIE that most significantly impact the VIE’s economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of this VIE and therefore consolidates the VIE.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income for the three and nine months ended September 30, 2026 of $2 million and $6 million, respectively, and for the three and nine months ended September 30, 2025 of $4 million and $13 million, respectively. 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 the VIE (dollars in thousands):

Assets of the VIE 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 the VIE upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, 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 VIE’s noncontrolling equity participants and take title to the leased Unit 2 interest, which, if appropriate, may be required to be written-down in value. If such an event were to occur during the lease period, APS may be required to pay the noncontrolling equity participant approximately $177 million in 2026 and up to $267 million over the lease term.

For regulatory ratemaking purposes, the lease agreement continues to be treated as an operating lease, and as a result, we have recorded a regulatory asset relating to the arrangement.

10. 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.

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 14 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 13 for details relating to Pinnacle West’s equity forward sale agreements and 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 7. 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):

Gains and Losses from Energy Derivative Instruments

For the three and nine months ended September 30, 2026 and 2025, APS had no energy derivative instruments in designated accounting hedging relationships.

The following table provides information about gains and losses from energy derivative instruments not designated as accounting hedging instruments (dollars in thousands):

(a)Amounts are before the effect of PSA deferrals.

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 (dollars in thousands):

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)No cash collateral has been provided to or received by 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 $5,746 thousand and cash margin provided to counterparties of $5 thousand.

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)No cash collateral has been provided to or received by 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 $2,566 thousand and cash margin provided to counterparties of $5 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 September 30, 2026, we havetwo counterparties with positive exposure greater than 35% of Pinnacle West’s $1.4 million of net risk management assets. This exposure relates to ISDA master agreements with the respective counterparties. The counterparties are rated as investment grade by S&P Global. 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 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 S&P Global or Fitch or Baa3 for Moody’s).

The following table provides information about our energy derivative instruments that have credit-risk-related contingent features (dollars in thousands):

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

As of September 30, 2026, we also have energy related non-derivative instrument contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $711 million if our debt credit ratings were to fall below investment grade.

11. 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 DOE in the 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 paid 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 is currently in the process of pursuing an extension of the settlement to cover costs paid through December 31, 2028.

APS has recovered costs paid from July 1, 2011, through October 31, 2025, fortwelve claims pursuant to the terms of the August 15, 2014 settlement agreement. The DOE has approved and paid approximately $189.7 million for these claims (APS’s share is approximately $55.2 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 ACC’s decision from the 2017 rate case, this regulatory liability is being refunded to customers. On November 2, 2026, APS submitted its thirteenth claim pursuant to the terms of the settlement agreement in the amount of approximately $21.3 million (APS’s share is approximately $6.2 million).

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 liability for a nuclear incident up to approximately $16.4 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 $15.9 billionof 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 thethree Palo Verde units, APS’s maximum retrospective premium per incident for allthree 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 thethree units. The property damage, decontamination, and accidental outage insurance are provided by NEIL. APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumul ated funds. The maximum amount APS could incur under the current NEIL policies totals approximately$24.9 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, Palo Verde would be liable to provide approximately $68.9 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.

Nuclear Wage Class Action Lawsuit

On July 11, 2025, APS, together with all 25 other U.S. nuclear power plant operators, was named in a class action lawsuit brought in the U.S. District Court in Maryland. The lawsuit alleges the country’s nuclear operators have violated antitrust laws by agreeing to exchange compensation information and suppress compensation. The class action complaint has been brought on behalf of all persons employed in nuclear power generation in the U.S. from May 1, 2003 until the present and alleges violations of the Sherman Act. The complaint was dismissed without prejudice on August 5, 2026 and an amended complaint was filed on October 8, 2026. We are unable at this time to predict the outcome of this matter and whether it will have a material impact on our financial position, results of operations, or cash flows.

Pinnacle West has established a captive insurance program to supplement commercial and mutual 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 commercial and mutual insurance coverage. 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. In addition to the policies obtained through the Captive, Pinnacle West also has commercial and mutual insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs. See Note 9 for additional details.

Fuel and Purchased Power Commitments and Purchase Obligations

As of September 30, 2026, our fuel and purchased power and purchase obligation commitments have increased by $4.8 billion from the information provided in our 2025 Form 10-K, primarily due to gas tolling lease contracts and a new coal supply agreement relating to Four Corners. See Note 17 for additional information regarding the gas tolling lease contracts.

Other than the items described above, there have been no material changes, as of September 30, 2026, outside the normal course of business in contractual obligations from the information provided in our 2025 Form 10-K. See Note 6 for discussion regarding changes in our short-term and long-term debt obligations.

Superfund and Other Related Matters

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 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, 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 RI/FS. The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. EPA notified APS that the remedial investigation and feasibility study (“RI/FS”) was approved on September 11, 2024. On September 25, 2025, EPA executed a final ROD adopting the OU3 remedies proposed in the approved RI/FS OU3. APS’s expenditures related to this investigation and study are approximately $3 million. APS anticipates it may incur additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS and ROD are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated; however, APS does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

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. At this time, a proposed consent decree that would resolve APS’s liability in these lawsuits for an immaterial amount is currently pending before the U.S. District Court for Arizona. APS is unable to predict the outcome of the District Court’s consideration of this proposed settlement; 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 the Ocotillo site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing PFAS at the Ocotillo site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash Superfund site. The South Indian Bend Wash Superfund site includes the Ocotillo 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 South Indian Bend Wash site, including Ocotillo, 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 GHG, 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.

Coal Combustion Waste

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCRs, such as fly ash and bottom ash (the “CCR Rule”). 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, 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 Act in 2016, 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. 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 EPA, which will have to approve the entire state program before it is operational. It remains unclear when EPA would approve that permitting program pursuant to the Water Infrastructure Improvements for the Nation Act.

•On December 19, 2019, 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 and on May 28, 2026, EPA published notice reopening the comment period on this proposal (the “2020 Proposed Federal CCR Permit Program Rule”). At this time, EPA is considering the estimated time needed to compile materials for site specific issues deferred to permitting; whether a six-month deadline after publication of the final permitting rule in the Federal Register is sufficient for the first tier of permit applications; how best to implement electronic permitting for both EPA-issued CCR permits and states that are implementing the CCR permitting program in lieu of EPA; and whether general permitting mechanisms can be used as part of state or federal permitting efforts for CCR management.

•On March 1, 2018, as a result of a settlement with certain environmental groups, 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.

We cannot predict the outcome of these regulatory proceedings or when 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 CCRMUs, which contain at least 1,000 tons of CCR, broadly encompasses any location at an operating coal-fired power plant where CCRs would have been placed on land. 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. Under EPA’s legacy 2024 CCRMU rule, initial CCRMU site surveys were originally due to be completed by February 2026 and final site investigation reports by February 2027.

On February 10, 2026, EPA published a final rule extending multiple compliance deadlines applicable to CCRMUs established under the prior rule. The final rule extends the deadline for completing Parts One and Two of Facility Evaluation Reports by one year to February 2027 and February 2028, respectively. EPA also extended associated compliance deadlines for groundwater monitoring and certain closure requirements. Subsequently, on April 9, 2026, EPA proposed a new regulation that contemplates a range of revisions to the 2024 legacy CCRMU rule, including full elimination of the 2024 standards among other alterations. EPA also proposes to expand the categories of activities that meet the definition of “beneficial use” of CCR, which is exempt from most federal CCR regulatory restrictions. In addition, EPA is proposing to authorize certain risk-based compliance alternatives for facilities subject to state or federal CCR permitting, which would allow adjustments to default standards for groundwater monitoring, groundwater protection standards, closure and post-closure care requirements, and additional measures concerning beneficial use.

APS is still in the process of evaluating the impacts of these CCRMU regulations on its business and cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules. 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 the pending legacy 2024 CCRMU rule amendments and APS’s evaluations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS has disposed of CCR in ash ponds and dry storage areas at Cholla, prior to ceasing coal-fired operations there, and Four Corners. The CCR Rule requires ongoing, phased groundwater monitoring to evaluate whether CCR disposal at our facilities has impacted groundwater. As of October 2018, APS completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. Based on this trigger, APS determined that several of its CCR disposal units at Cholla and Four Corners need to undergo groundwater corrective action. In addition, under the current regulations, all such disposal units had to cease operating and initiate closure as of April 11, 2021 (except for those disposal units at Cholla that had been subject to alternative closure, which initiated closure work on June 30, 2025). APS completed the assessments of corrective measures for subject CCR units at Four Corners and Cholla on June 14, 2019, and has solicited input from the public and hosted public hearings as part of this process. APS selected groundwater remedies for the closed CCR disposal units at Four Corners on December 31, 2025. Groundwater remedies were then selected for the closed CCR disposal units at Cholla on May 29, 2026. APS estimated its share of corrective action and monitoring costs at Four Corners and Cholla prior to remedy selection, and those estimates are captured within the AROs and removal costs within Regulatory Liabilities. At this time, APS does not believe that any potential changes to the cost estimate associated with remedy selection at Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows. However, as APS continues to implement the CCR Rule’s corrective action process, ongoing review and revisions to these cost estimates may be required due to the uncertainties inherent in long-term groundwater remediation programs.

EPA Power Plant Carbon Regulations

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, 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 EPA on June 19, 2019 and replaced by the Affordable Clean Energy regulations, which were a far narrower set of rules. While the U.S. Court of Appeals for the D.C. Circuit subsequently vacated the Affordable Clean Energy regulations on January 19, 2021, and ordered a remand for 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 EPA’s authority under the Clean Air Act.

In the latest final regulations governing power plant carbon dioxide emissions, released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants. However, EPA has now taken final action to repeal the vast majority of those 2024 standards. On September 17, 2026, EPA concurrently published in the Federal Register both a final Partial Repeal Rule and a proposed Supplemental Full Repeal Rule. The final repeal action eliminates the CCS requirements in the 2024 standards for existing coal-fired power plants and new baseload natural gas-fired power plants (those operating over a 40% capacity factor), while also eliminating the gas co-firing requirements for existing coal-fired power plants and all requirements for existing gas- and oil-fired steam generating units. This action leaves in place the 2024 efficiency-based carbon performance standards for new natural gas power plants. The Supplemental Full Repeal Rule proposal, however, contemplates elimination of all 2024 carbon-emission standards, with comments due on November 2, 2026.

As to the final Partial Repeal Rule, multiple health and climate organizations filed a petition for review of this action in the D.C. Circuit Court of Appeals on September 17, 2026. In addition, a petition for review was also filed by a coalition of 22 states and cities, including Arizona, on October 1, 2026, challenging the Partial Repeal Rule. Other petitions to EPA’s final Partial Rule Repeal are due by

November 16, 2026 and motions to intervene in the case were due by October 19, 2026. We cannot predict the outcome of this litigation or of any future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.

On February 18, 2026, EPA’s repeal of the 2009 “Endangerment Finding” was finalized and published in the Federal Register. This action is expected to provide legal and regulatory support for EPA’s pending proposals seeking to eliminate or significantly limit the scope of the current EPA carbon emission standards and guidelines for new and existing power plants. The repeal of the “Endangerment Finding” is subject to judicial review, with lawsuits being filed on February 18, 2026 in the D.C. Circuit Court of Appeals seeking to challenge the repeal. On October 5, 2026, the D.C. Circuit Court rejected a request submitted by petitioners on May 20, 2026 for an emergency stay of EPA’s Repeal Rule, thereby resulting in EPA’s rollback of the Endangerment Finding remaining in effect during the ongoing legal challenge. We cannot predict the outcome of the litigation.

Effluent Limitation Guidelines

EPA published ELG on October 13, 2020, and, based on those guidelines, APS completed a 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 EPA finalized in September 2015. However, on April 25, 2024, 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 (“2024 ELG Rule”). 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.

On December 31, 2025, EPA published a final rule extending by five years the compliance deadlines for achieving the 2024 zero-discharge standards for bottom ash transport wastewater from year-end 2029 to year-end 2034, among other changes to the 2024 rulemaking. EPA is also collecting additional information on zero-discharge technologies, including cost and performance data, to inform future potential rulemakings to modify or relax the current zero-discharge ELG standards. We cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at modifying the current ELG standards.

On May 18, 2026, EPA published a proposed rule to revise the 2024 ELG Rule limits and standards for unmanaged combustion residual leachate (“CRL”), or water leaking from landfills or surface impoundments that contains coal combustion residuals. The proposal would introduce flexible, site-specific approaches for managing unmanaged CRL at steam electric power plants, such as Four Corners, rather than applying a strict, national zero-discharge framework across the board as implemented under the 2024 ELG Rule. APS cannot predict the outcome of this rulemaking.

EPA Good Neighbor Proposal for Arizona

On March 15, 2023, 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 NAAQS. Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for NOx emissions. While Arizona was not among the 23 states subject to 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 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 EPA’s Good Neighbor Plan upon finalization of this proposal. 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 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, 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, EPA announced its intention to reconsider the Good Neighbor Plan and on January 30, 2026, EPA published a proposed rule in the Federal Register that would approve Arizona’s and New Mexico’s State Implementation Plans concerning the cross-state transport of ozone forming emissions. Such approval, if finalized as proposed, would remove APS’s operations in Arizona and New Mexico from the scope of future efforts to regulate such emissions. APS cannot predict the outcome of this pending regulatory action nor when EPA may take final action on this proposal. If finalized as proposed, this action would then be subject to judicial review and APS cannot predict the outcome of such litigation, if any arises. In addition, APS cannot predict the outcome of any future EPA efforts to add Arizona or New Mexico to a future federal program addressing the cross-state transport of ozone-forming emissions. Should a federal program like the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have a 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.

Mercury and Air Toxics Standard (“MATS”) Regulations

On February 20, 2026, EPA issued a final rule repealing the 2024 revisions to MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants. The repeal of the 2024 amendment means that MATS regulations revert to the pre-existing framework for MATS emission limits established in 2012. As a result, the 2024 revisions that would have increased the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and required the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing) will not take effect for existing coal-fired power plants, such as Four Corners.

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.

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 September 30, 2026, standby letters of credit totaled approximately $30.4 million and will expire through 2027, and surety bonds totaled approximately $25 million and will expire through 2028. The underlying liabilities secured 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 remaining Palo Verde sale leaseback transaction 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 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 September 30, 2026. 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 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 to date. 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 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 September 30, 2026, there is approximately $24.0 million remaining relating to these PTC Guarantees that are expected to terminate by 2031.

Pinnacle West issued various performance guarantees in connection with a joint venture project, the Kūpono Solar Project, by BCE, a former subsidiary of Pinnacle West. BCE was sold to Ameresco in 2024 (the “BCE Sale”). Subsequent to the BCE Sale, Pinnacle West continues to maintain these Kūpono Solar Project investment financing guarantees and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote. 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.

12. Other Income and Other Expense

The following table provides detail of Pinnacle West’s consolidated other income and other expense (dollars in thousands):

(a)Primarily relates to El Dorado investment activities. See Note 19.

The following table provides detail of APS’s other income and other expense (dollars in thousands):

13. Common Stock Equity and Earnings Per Share

At-the-Market Program

On November 8, 2024, Pinnacle West opened an ATM Program (the “2024 ATM Program”), pursuant to which Pinnacle West may sell, from time to time, up to $900 million of its common stock through an at-the-market equity distribution program, which includes the ability to enter into forward sale agreements.

As of September 30, 2026, Pinnacle West hadfourteen outstanding forward sale agreements under the 2024 ATM Program (each an “ATM Forward Sale Agreement”). These agreements relate to approximately $900 million, on a gross basis, of common stock and may be settled at Pinnacle West’s discretion by issuing shares at the applicable forward sales price or, alternatively, by delivering cash in lieu of shares. Following entry into these forward sale agreements, the $900 million of sales of common stock contemplated by the 2024 ATM Program have been substantially completed and the program has been terminated.

On August 4, 2026, Pinnacle West opened another ATM Program (the “2026 ATM Program”), pursuant to which Pinnacle West may sell, from time to time, up to $500 million of its common stock, which includes the ability to enter into forward sale agreements.

As of September 30, 2026, Pinnacle West hadtwo outstanding forward sale agreements under the 2026 ATM Program. These agreements relate to approximately $150 million, on a gross basis, of common stock and may be settled at Pinnacle West’s discretion by issuing shares at the applicable forward sales price or, alternatively, by delivering cash in lieu of shares. Effective October 5, 2026, Pinnacle West entered into a third forward sale agreement under the 2026 ATM Program, relating to a total of $90 million, on a gross basis, of common stock, with a maturity date of October 2, 2028.

The following table presents information about the outstanding forward sale agreements pursuant to ATM Programs as of September 30, 2026 based on their contractual terms at the effective date of the agreement, including the aggregate contractual values utilizing the applicable forward sale prices, which may differ from the gross amount of common stock referenced above (dollars and shares in thousands):

(a) Final maturity date varies by agreement and may be extended. Maturity date set forth in the table is as extended, if applicable.

(b) Actual cash proceeds will be impacted by the timing of settlement, net of applicable fees.

Non-ATM February 2024 Forward Sale Agreements

In addition to the ATM Program forward sale agreements, Pinnacle West also has forward sale agreements that were entered into on February 28, 2024 (the “February 2024 Forward Sale Agreements”). These agreements may be settled at Pinnacle West’s discretion by issuing shares of Pinnacle West common stock and receiving 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. The February 2024 Forward Sale Agreements were partially settled in December 2024, September 2025, and December 2025. In August 2025, Pinnacle West amended the February 2024 Forward Sale Agreements with Wells Fargo Bank, National Association, to extend the maturity date of those forward confirmations to December 31, 2026.

The following table presents information about the February 2024 Forward Sale Agreements as of September 30, 2026 (dollars in thousands, except price per share):

(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 (the “Convertible Notes”), which are senior unsecured obligations of Pinnacle West and will mature on June 15, 2027. Interest is 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 thefive 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 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 September 30, 2026, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as current maturities of long term debt on Pinnacle West’s Condensed Consolidated Balance Sheets with a carrying amount of $525 million, net of approximately $2 million in unamortized debt issuance costs. The estimated fair value of the Convertible Notes as of September 30, 2026 was approximately $558 million (Level 2 within the fair value hierarchy).

As of September 30, 2026, based on Pinnacle West’s average stock price and the relevant terms of the Convertible Notes, shares related to the potential conversion of the Convertible Notes were included in diluted EPS, but no shares were included in basic EPS.

Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted EPS (dollars and shares in thousands, except EPS amounts):

(a) For the three and nine months ended September 30, 2026, there were 84,285 and 17,489 shares, respectively, excluded from the calculation of diluted weighted-average common shares as their inclusion would have been antidilutive. For the three and nine months ended September 30, 2025, there were 16,327 and 11,678 shares, respectively, excluded from the calculation of diluted weighted-average common shares as their inclusion would have been antidilutive.

(b)No shares related to the Convertible Notes were excluded from diluted weighted-average common shares for the three and nine months ended September 30, 2026. For the three and nine months ended September 30, 2025, potentially issuable shares of 140,252 and 128,129, respectively, were excluded from the diluted weighted-average common shares calculation as their inclusion would have been antidilutive.

Pinnacle West’s forward sale agreements are classified as equity transactions and are not recorded on the Pinnacle West Condensed Consolidated Balance Sheets until shares are settled. Delivery of shares to settle equity forward agreements will result in dilution to basic EPS upon settlement. Prior to settlement, the potentially issuable shares are reflected in our diluted EPS calculations using the treasury stock method. Under this method, the number of shares, if any, that would be issued upon settlement is reduced by the number of shares that could be purchased by Pinnacle West in the market with the proceeds received from issuance (based on the average market price during the reporting period). Share dilution occurs when the average market price of our stock during the reporting period is higher than the adjusted forward sale price as of the end of the reporting period.

14. 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:

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.

Certain instruments have been valued using the concept of net asset value (“NAV”) as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV as a practical expedient are included in our fair value disclosures; however, in accordance with GAAP, are not classified within the fair value hierarchy levels.

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 2025 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.

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 15 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 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 service auditor’s reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

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.

Fair Value Tables

The following table presents the fair value as of September 30, 2026 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

(a)Represents counterparty netting, margin, and collateral. See Note 10.

(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 $41.1 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.

The following table presents the fair value as of December 31, 2025 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

(a)Represents counterparty netting, margin, and collateral. See Note 10.

(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 $40.3 million related to Pinnacle West’s Captive investments that are classified within Level 1 equity securities. See Note 9.

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.

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 September 30, 2026 and December 31, 2025 (dollars in thousands):

(a)Includes swaps and physical and financial contracts.

(b)Unobservable inputs were weighted by the relative fair value of the instrument.

(a)Includes swaps and physical and financial contracts.

(b)Unobservable inputs were weighted by the relative fair value of the instrument.

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):

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

The carrying values of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 6 for our long-term debt fair values.

15. 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 14 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 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 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 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. 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. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

Pinnacle West has investments held by 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):

(a)As of September 30, 2026, the amortized cost basis of these available-for-sale investments is $1,247 million.

(b)Primarily represents net pending securities sales and purchases.

(c)All amounts pertain to APS, with the exception of $41.1 million of other special use fund investments in equity securities relating to investments held by the Captive.

(d)All amounts pertain to APS, with the exception of $2.2 million of unrealized gains relating to investments held by the Captive.

(a)As of December 31, 2025, the amortized cost basis of these available-for-sale investments is $1,265 million.

(c)All amounts pertain to APS, with the exception of $40.3 million of other special use fund investments in equity securities relating to investments held by the Captive.

(d)All amounts pertain to APS, with the exception of $3.2 million of unrealized gains relating to investments held by 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):

(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.

(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 $5.8 million of other special use fund proceeds from the sale of securities relating to investments held by the Captive.

(c) All amounts pertain to APS, with the exception of $50.5 million of other special use fund proceeds from the sale of securities relating to investments held by the Captive.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities summarized by contractual maturities as of September 30, 2026 is as follows (dollars in thousands):

16. Changes in Accumulated Other Comprehensive Loss

The following tables show the changes in Pinnacle West’s consolidated accumulated other comprehensive income (loss), including reclassification adjustments, net of tax, by component (dollars in thousands):

The following tables show the changes in APS’s accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component (dollars in thousands):

17. 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 power purchase or PPAs and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2026 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. The 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 from these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. In September 2025, two of thethree leased interests were purchased by APS. As of September 30, 2026, one VIE lease arrangement remains in effect. See Note 9.

APS is party to PPAs that allow it 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.

During the first quarter of 2026, APS modifiedtwo existing purchase power operating lease agreements. These agreements relate to natural-gas tolling purchase power agreements. Among other changes, the modifications extend the expiration date of the leases, change the periods of use, and modify the pricing. The modified lease agreements continue to qualify as operating lease agreements. These will now terminate in October 2038 and December 2046.

APS has executed various energy storage PPAs 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 September 2026.

The following table provides information related to our lease costs (dollars in thousands):

(a) Primarily relates to PPA lease contracts.

Lease costs are primarily included as a component of operating expenses on our Condensed Consolidated Statements of Income. Lease costs relating to PPAs and energy storage PPA 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 7. 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 PPA lease contracts. Payments under most renewable PPA 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.

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):

We recognize lease assets and liabilities upon lease commencement. As of September 30, 2026, 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 $8.4 billion over the terms of the agreements. These arrangements primarily relate to energy storage PPA assets. We expect lease commencement dates ranging from October 2026 through June 2028, with lease terms expiring through June 2048.

The following tables provide other additional information related to operating lease liabilities (dollars in thousands):

(a)Primarily relates totwo PPA operating lease agreements that were modified in 2026 along with various new energy storage operating lease agreements that commenced in 2026.

(b)Primarily relates to the various new energy storage operating lease agreements that commenced in 2025.

(c)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.

18. Asset Retirement Obligations

During the nine months ended September 30, 2026, the Company revised its cost estimates for existing asset retirement obligations for the following:

•Cholla coal-fired power plant related to the closure of ponds and facilities, which resulted in an increase to the ARO of approximately $10 million, primarily due to increased cost estimates associated with the CCR Rule.

APS has also recorded the initial investigation and assessment costs related to the EPA rule for legacy CCR surface impoundments and CCRMUs. At this time, APS is still evaluating the financial impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2027 and final site investigation reports to be finalized by February 2028 in accordance with the rule published by EPA on February 10, 2026, extending the compliance deadlines. Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU ARO. 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.

See additional details in Notes 7 and 11.

The following table shows the change in our AROs for the nine months ended September 30, 2026 (dollars in thousands):

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See Note 7 for detail of regulatory liabilities.

19. El Dorado Equity Investments

Equity Method Investments

El Dorado holds investments in equity securities accounted for under the equity method. The equity method of accounting is applied when we have the ability to exercise significant influence over the operating and financial policies of an investee. The equity method has been applied to El Dorado’s equity investment holdings in SAI and Copper Sky.

SAI — SAI Advanced Power Solutions, Inc. (“SAI”) is a private corporation that manufactures electrical switchgear equipment used by data centers. El Dorado holds common stock in SAI and maintains a seat on SAI’s board of directors. El Dorado’s ownership increased to 17.99% in the second quarter of 2026 as a result of SAI’s Phase 1 repurchases, and increased to 24.47% in the third quarter of 2026 as a result of SAI’s Phase II repurchases, which reduced the number of outstanding shares.

Copper Sky — Copper Sky, LLC (“Copper Sky”), is a limited liability company 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. El Dorado holds Class A Membership interests in the fund.

These equity method investments are included in the other assets line item on Pinnacle West’s Condensed Consolidated Balance Sheets. The following table presents El Dorado’s ownership percentages and carrying value of investments accounted for under the equity method (dollars in millions):

(a)El Dorado has no further funding commitments to SAI.

(b)El Dorado has a $25.0 million funding commitment to Copper Sky, of which approximately $20.0 million has been funded as of September 30, 2026.

Our share of the investees’ earnings or losses are recognized in other income and other expense, respectively on Pinnacle West’s Condensed Consolidated Statements of Income. For the nine months ended September 30, 2026, the net equity method earnings relating to these investments was $20.9 million. For the nine months ended September 30, 2025, the net equity method earnings relating to these investments was $25.4 million.

Other Investments

El Dorado holds investments in other equity securities to which the equity method of accounting does not apply due to lack of significant influence over the investees’ operating and financial policies. These equity investments do not have readily determinable fair values, and we have elected the measurement alternative for these investments. Investments accounted for under the measurement alternative are carried at cost adjusted for impairments or observable price changes. The Pinnacle West Condensed Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025 include $26.8 million and $25.1 million, respectively, relating to these other El Dorado equity investments. These investments are carried at cost, as no impairments or observable price changes have occurred as of September 30, 2026.