PNW 10-K Fiscal year ended Dec. 31, 2024

Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 21, 2025 are incorporated by reference into Part III hereof.

Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

APS’s cybersecurity group (the “Cybersecurity Group”) is comprised of cybersecurity analysts, engineers, architects, and others, led by the Director of Cybersecurity, who reports to APS’s Vice President, Operations Support. The Director of Cybersecurity has more than twenty years of experience in information technology and cybersecurity roles, with more than ten of those years at the Company. The Director of Cybersecurity also holds cybersecurity certifications from multiple certifying bodies and is active in utility cybersecurity professional organizations. The Cybersecurity Group has day-to-day responsibility for safeguarding the Company’s critical assets and assessing, identifying, and managing material risks from cybersecurity threats.

In fulfilling its responsibility, the Cybersecurity Group manages formal documented internal processes such as risk management and vulnerability scanning, as well as other processes, such as assessing threat intelligence, that include outside partners. Intelligence sharing comes from industry sources such as the Electricity Information Sharing and Analysis Center, government sources, as well as commercially purchased information sources. The Cybersecurity Group also engages third parties for assessments and audits of its systems periodically and as needed. Such assessments and audits may include, among other things, pre-production evaluation of technologies, overall program assessments, and compliance program assessments including audits by our regulators.

Depending on the products and services provided and the potential for data exchange and technology risk, we may require vendors and service providers to pass APS’s vendor risk management program, which sets forth security and data protection requirements, as a condition to doing or continuing to do business with us. For contracts with vendors that will handle or have access to certain sensitive data, APS requires contractual provisions setting forth cybersecurity controls, vulnerability management, secure development practices, and other security and data protection requirements. A subset of vendors that meet a predetermined risk profile due to strategic relationships, technology risk, or other factors is continually monitored by a third-party risk management service, and the Company annually reviews independent assessments of these vendors.

The Cybersecurity Group also has documented processes for identifying, responding to, and internally escalating cybersecurity incidents to management and the Board of Directors. Once an incident meets certain criteria, the Company’s Cybersecurity Incident Command or, in the most severe cases that

---

impact the entire Company, the Corporate Emergency Operations Center is activated and formal response procedures are followed to address the incident. The Cybersecurity Group has a formal incident response plan that details response and escalation procedures, including activation of a Cybersecurity Disclosure Committee, consisting of the Chief Financial Officer and the General Counsel, to assess an incident’s materiality with input as needed from the Director of Cybersecurity, Chief Accounting Officer, Chief Information Officer, and others, including outside advisors.

Cybersecurity risk management has been integrated into the Company’s overall enterprise risk management program (the “Enterprise Risk Management Program”) through policies and processes that implement a risk management framework designed to identify, manage, and monitor business unit risks throughout the organization. The Enterprise Risk Management Program is overseen by an executive committee (the “ Executive Risk Committee ”), which meets at least quarterly and is comprised of members holding executive leadership positions in the Company, including the Chairman and Chief Executive Officer, President, and other Executive and Senior Vice Presidents, and is chaired and sponsored by the Chief Financial Officer. Every year, as a part of the Enterprise Risk Management Program, risks affecting the Company are identified. For 2024, cybersecurity was identified as a risk. The applicable subject matter experts brief the Company’s Board of Directors on the status of all top enterprise risks at least once per year. Finally, the Nuclear and Operating Committee of the Company’s Board of Directors provides ultimate oversight of cybersecurity risk and also receives briefings at least twice per year from the Cybersecurity Group, and notable audit findings relating to cybersecurity are aggregated and provided to the Board of Directors’ Audit Committee.

To date, we do not believe there have been risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect Pinnacle West or APS. However, there is no assurance that will continue to be the case. If a significant cybersecurity event or incident were to occur, our ability to fulfill our critical business functions and our business strategy, results of operations, and financial condition could all be materially impacted. See the risk factor entitled, “We are subject to cybersecurity risks and risks of unauthorized access to our systems that could adversely affect our business and financial condition” in Item 1A—Risk Factors for more information.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado and PNW Power. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings and is expected to continue to do so.  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 was created in September 2023 to hold certain investments in wind and transmission joint projects. See Note 20 for more information on PNW Power.

BCE was a Pinnacle West subsidiary that was formed in 2014. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which all of our equity interest in BCE was sold. The sale was completed on January 12, 2024. See Note 20 for more information relating to the sale of BCE.

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries, including APS, El Dorado, and PNW Power, as well as our former subsidiary BCE until its sale. Pinnacle West’s Consolidated Financial Statements also include the accounts of a VIE relating to a Captive Insurance Cell (“Captive”). APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate Variable Interest Entities (each a “VIE”) for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. We have also determined that Pinnacle West is the primary beneficiary of a protected captive insurance cell VIE, and therefore Pinnacle West consolidates this insurance cell. See Note 17 for additional information.

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

---

Regulatory Accounting

APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.

Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential commission-ordered refunds to customers on regulatory liabilities.

See Note 3 for additional information.

Electric Revenues

Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Certain cost recovery mechanisms may qualify as alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

See Notes 2 and 3 for additional information.

---

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable 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.

See Note 2 for additional information.

Property, Plant and Equipment

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities.  We report utility plant at its original cost, which includes:

• material and labor;

• contractor costs;

• capitalized leases;

• construction overhead costs (where applicable); and

• AFUDC.

Pinnacle West’s property, plant and equipment included in the December 31, 2024, and 2023 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:			2024						2023
Generation			$	11,111,915					$	10,446,291
Transmission			4,135,970						3,773,253
Distribution			9,016,843						8,448,293
General plant			1,596,222						1,543,330
Plant in service and held for future use			25,860,950						24,211,167
Accumulated depreciation and amortization			( 9,027,426 )						( 8,408,040 )
Net			16,833,524						15,803,127
Construction work in progress			1,592,659						1,724,004
Palo Verde sale leaseback, net of accumulated depreciation			82,556						86,426
Intangible assets, net of accumulated amortization			591,310						267,110
Nuclear fuel, net of accumulated amortization			97,850						99,490
Total property, plant and equipment			$	19,197,899					$	17,980,157

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and

---

the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 11 for additional information.

APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for AROs.  APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2024, were as follows:

• Steam generation — 11 years;

• Nuclear plant — 25 years;

• Other generation — 18 years;

• Transmission — 38 years;

• Distribution — 33 years; and

• General plant — 7 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $ 723 million in 2024, $ 669 million in 2023, and $ 632 million in 2022. For the years 2022 through 2024, the depreciation rates ranged from a low of 1.37 % to a high of 12.15 %.  The weighted-average depreciation rate was 3.13 % in 2024, 2.98 % in 2023, and 3.03 % in 2022.

Asset Retirement Obligations

APS has AROs for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde ARO primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of irradiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation AROs primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have AROs because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the ARO related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 11 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

---

AFUDC was calculated by using a composite rate of 6.23 % for 2024, 6.29 % for 2023, and 5.75 % for 2022.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021.  On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provided a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic.  APS adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacted the AFUDC composite rate in 2021 and for the three-month period ended March 31, 2022.  Furthermore, the change in the composite rate calculation did not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.

Materials and Supplies

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or net realizable value, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 6 for additional information.

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts, and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

---

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.

See Note 12 for additional information about fair value measurements.

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial 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 as well as interest rate risk.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  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 expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income, or cash flows.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.

See Note 15 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred, and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

The Captive’s contingent losses may include an amount for losses incurred but not reported (“IBNR”). A reserve for IBNR is based upon a loss analysis prepared using actuarial assumptions and techniques. Such liabilities are necessarily based on estimates and the ultimate liability may be in excess of or less than the amount provided. The methods for making such estimates and for establishing the resulting liability are continually reviewed, and any adjustments for the review process as well as differences between estimates and ultimate payments are reflected in earnings currently. As of December 31, 2024, no IBNR reserve relating to our captive insurance cell has been recorded. See Note 17.

---

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan.  We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.

See Note 7 for additional information on pension and other postretirement benefits.

Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $ 0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we accrued a receivable and an offsetting regulatory liability through the settlement period ended December of 2024. See Note 10 for information on spent nuclear fuel disposal costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50 % likely of being realized upon settlement for all known and measurable tax exposures. See Note 4 for additional discussion.

---

Cash and Cash Equivalents

We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):

												Year Ended December 31,
																		2024						2023						2022
Cash paid during the period for:
Income taxes, net of refunds																		$	133,968					$	8,788					$	46,227
Interest, net of amounts capitalized																		360,349						310,996						245,271
Significant non-cash investing and financing activities:
Accrued capital expenditures																		$	257,494					$	206,269					$	114,999
Dividends accrued but not yet paid																		106,592						99,813						97,895
BCE Sale non-cash consideration (Note 20)																		—						28,262						—

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):

												Year Ended December 31,
																		2024						2023						2022
Cash paid during the period for:
Income taxes, net of refunds																		$	179,013					$	21,734					$	95,985
Interest, net of amounts capitalized																		299,799						267,261						227,159
Significant non-cash investing and financing activities:
Accrued capital expenditures																		$	257,494					$	206,269					$	116,533
Dividends accrued but not yet paid																		107,200						99,800						97,900

Intangible Assets

We have separately disclosed intangible assets on Pinnacle West’s Consolidated Balance Sheets. The intangible assets relate primarily to APS’s internal-use software. We have no goodwill recorded. The intangible assets are amortized over their finite useful lives. Amortization expense was $ 136 million in 2024, $ 90 million in 2023, and $ 84 million in 2022.  Estimated amortization expense on existing intangible assets over the next five years is $ 106 million in 2025, $ 77 million in 2026, $ 43 million in 2027, $ 25 million in 2028, and $ 14 million in 2029.  At December 31, 2024, the weighted-average remaining amortization period for intangible assets was 5 years.

Investments

El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20 % ownership and no significant influence).

---

PNW Power holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20 % ownership and no significant influence).

Our investments in the nuclear decommissioning trusts, and other special use funds, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 12 and 18 for more information on these investments.

Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant or facility, APS obtains substantially all of the economic benefits from the use of the facility and has the right to direct the use of the facility. Purchased power lease contracts may also include energy storage facilities. Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 3 . We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 for information on our lease agreements.

Business Segments

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) 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”). The 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, the 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, assets, and other reportable segment items, see the APS’s Consolidated Income Statements, APS Consolidated Balance Sheets, and APS Consolidated Statements of Cash Flows. The following tables reconcile our reportable segment’s revenues, significant expenses, net income, and assets to the Pinnacle West Consolidated amounts (dollars in millions):

			Year Ended December 31,
			2024												2023												2022
			Regulated Electricity Segment			Other			Pinnacle West Consolidated						Regulated Electricity Segment			Other			Pinnacle West Consolidated						Regulated Electricity Segment			Other			Pinnacle West Consolidated
Operating Revenues			$	5,125		$	—		$	5,125					$	4,696		$	—		$	4,696					$	4,324		$	—		$	4,324
Fuel & Purchase Power			( 1,823 )			—			( 1,823 )						( 1,793 )			—			( 1,793 )						( 1,629 )			—			( 1,629 )
Operations & Maintenance			( 1,159 )			( 6 )			( 1,165 )						( 1,044 )			( 15 )			( 1,059 )						( 974 )			( 13 )			( 987 )
Depreciation & Amortization			( 895 )			—			( 895 )						( 794 )			—			( 794 )						( 753 )			—			( 753 )
Taxes other than income taxes			( 227 )			—			( 227 )						( 224 )			—			( 224 )						( 220 )			—			( 220 )
Pension and other postretirement non-service credits, net			49			—			49						42			( 1 )			41						99			( 1 )			98
Other income and expenses, net (a)			28			22			50						60			—			60						22			( 23 )			( 1 )
Interest expense and costs			( 312 )			( 65 )			( 377 )						( 285 )			( 46 )			( 331 )						( 236 )			( 20 )			( 256 )
Income Taxes			( 127 )			16			( 111 )						( 94 )			17			( 77 )						( 91 )			16			( 75 )
Less: income related to noncontrolling interest			( 17 )			—			( 17 )						( 17 )			—			( 17 )						( 17 )			—			( 17 )
Net Income (loss)			$	642		$	( 33 )		$	609					$	547		$	( 45 )		$	502					$	525		$	( 41 )		$	484

(a) See Note 16 for additional details regarding other income and other expenses. Other income includes allowance for equity funds used during construction, see the APS Consolidated Income Statements.

			December 31, 2024												December 31, 2023
			Regulated Electricity Segment			Other			PNW Consolidated						Regulated Electricity Segment			Other			PNW Consolidated
Total Assets			$	25,988		$	115		$	26,103					$	24,516		$	145		$	24,661

---

Preferred Stock

At December 31, 2024, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $ 25 , $ 50 , and $ 100 par values, none of which was outstanding.

Sources of Revenue

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

															Year Ended December 31,
																											2024						2023						2022
Retail Electric Service
Residential																											$	2,562,822					$	2,289,196					$	2,046,111
Non-Residential																											2,334,925						2,048,416						1,767,616
Wholesale Energy Sales																											96,857						208,985						383,126
Transmission Services for Others																											119,038						138,631						116,628
Other Sources																											11,273						10,763						10,904
Total Operating Revenues																											$	5,124,915					$	4,695,991					$	4,324,385

Retail Electric Revenue. All of Pinnacle West’s retail electric revenue is generated by APS. Retail electric revenue is generated by the sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered, or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 21 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

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 year ended December 31, 2024, 2023 and 2022 were $ 5,073 million, $ 4,651 million, and $ 4,302 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 year ended December 31, 2024, 2023, and 2022 our revenues that do not qualify as revenue from contracts with customers were $ 52 million, $ 45 million, and $ 22 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 3 for a discussion of our regulatory cost recovery mechanisms.

Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and allowance for doubtful accounts.

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):

						Year Ended December 31,
						2024						2023						2022
Balance at beginning of period						$	22,433					$	23,778					$	25,354
Bad debt expense						35,799						23,399						17,006
Actual write-offs						( 33,383 )						( 24,744 )						( 18,582 )
Balance at end of period						$	24,849					$	22,433					$	23,778

APS expects to file an application with the ACC for its next general rate case mid-year 2025 and is continuing to evaluate the timing of such filing.

2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates.

On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order (“ROO”) in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”). The 2022 Rate Case ROO recommended, among other things, (i) a $ 523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55 % return on equity, (iii) a 0.25 % return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36 %, (v) 12 months of post-

---

test year plant and the inclusion of the Four Corners Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a 5.0 % return on the prepaid pension asset and a return of 5.35 % on the OPEB liability, and (ix) no disallowances on APS’s coal contracts.

The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $ 1.9 million of Renewable Energy Adjustment Charge (“REAC”) in the adjustor rather than base rates, (iii) a partial transfer of $ 27.1 million of LFCR funds to base rates, and (iv) the adoption of an increase in the annual PSA cap to $ 0.006 /kWh.

On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $ 491.7 million increase in the annual base revenue requirement, (ii) a 9.55 % return on equity, (iii) a 0.25 % return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39 %, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source request for proposal (“ASRFP”), and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $ 253.4 million and a roughly 8 % increase to the typical residential customer’s bill. The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.

Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association, Solar Energy Industries Association, 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. Following the limited rehearing, an Administrative Law Judge issued a ROO (the “Limited Rehearing ROO”) on December 3, 2024. The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers. On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing. The Commission has taken no action on these requests. In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the Commission’s decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.

---

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates (the “2019 Rate Case”). On August 2, 2021, an Administrative Law Judge issued a ROO in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

On November 2, 2021, the ACC approved the 2019 Rate Case ROO, with various amendments, that resulted in, among other things, (i) a return on equity of 8.70 %, which included a 20 basis points penalty; (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners selective catalytic reduction (“SCR”) project, with the exception of $ 215.5 million (see “Four Corners SCR Cost Recovery” below); (iii) the CCT plan including the following components: (a) a payment of $ 1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $ 10 million over three years to the Navajo Nation, (c) a payment of $ 0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $ 1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $ 1.25 million for the electrification of homes and businesses on the Navajo Nation reservation; and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, resulted in a total annual revenue decrease for APS of $ 4.8 million, excluding temporary payments and expenditures, under the CCT plan.

Consistent with the 2019 Rate Case decision, APS completed the following payments that are being recovered through rates related to the CCT: (i) $ 10 million to the Navajo Nation; (ii) $ 0.5 million to the Navajo County communities; and (iii) $ 1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $ 1.5 million to the Navajo Nation for CCT; (ii) $ 1.1 million to the Navajo County communities for CCT and economic development; and (iii) $ 1.25 million to the Hopi Tribe for CCT and economic development. The ACC also authorized $ 1.25 million to be spent for electrification of homes and businesses on each of the Navajo Nation and Hopi reservations. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory. The census work was completed in November 2022 and disbursement of the funds for electrification of homes and businesses is planned to be finalized after discussions with the Navajo Nation and the Hopi Tribe are completed. On February 22, 2024, the ACC voted to not approve any further CCT funding.

APS filed a Notice of Direct Appeal to the Arizona Court of Appeals on December 17, 2021 requesting review of certain aspects of the 2019 Rate Case. On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case. The Court vacated the 20 basis points penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority. Additionally, the Court vacated the disallowance of $ 215.5 million of APS’s Four Corners SCR investment. The Court remanded the issue to the ACC for further proceedings.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to allow recovery of the $ 215.5 million in costs related to the installation of the Four Corners SCR, a reversal of the 20 basis points reduction to APS’s return on equity from 8.9 % to 8.7 % as a result of the 2019 Rate Case decision, and recovery of $ 59.6 million in revenue lost by APS between December 2021 and June 20, 2023. On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through

---

the Court Resolution Surcharge (“CRS”) mechanism, which became effective on July 1, 2023. See “Court Resolution Surcharge” below for more information.

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 allows regulated utilities to propose formula rate plans in future rate cases. Proposed plans must be based on a historical test year, include an annual update with a true-up and an earnings test to ensure a utility earns within a 20 basis points band of its authorized return on equity. Proposed plans should also include an annual meeting and challenge periods for stakeholder feedback. Utilities that implement formula rates also must file a full rate case at least every five years unless an alternate schedule is set by the ACC. APS cannot predict the outcome of this matter.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms. See “2022 Retail Rate Case” above for modifications of adjustment mechanisms in the 2022 Rate Case.

Renewable Energy Standard . In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including, for example, solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five -year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its Integrated Resource Plan (“IRP”), and seek cost recovery in a rate process. Since the adopted clean energy rules differed substantially from the original ROO, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider ASRFP requirements and the IRP process. See “Energy Modernization Plan” below for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $ 93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $ 100.5 million. This budget included funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $ 20 million to $ 30 million in capital costs for the continuation of the APS Solar Communities program each year for a period of three years from the effective date of 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 2022. On May 18, 2022, the ACC approved the 2022

---

RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the ACC’s consideration at a future date.

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. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023. The ACC has not yet ruled on the 2024 RES Implementation Plan. APS cannot predict the outcome of this proceeding.

On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $ 92.7 million. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2024. The ACC has not yet ruled on the 2025 RES Implementation Plan. APS cannot predict the outcome of this proceeding.

On June 14, 2021, APS filed an application for approval of its Green Power Partners Program (“GPP”). On September 1, 2021, the ACC approved the application. On June 28, 2024, APS filed an application for approval of modifications to the GPP and requested a renewable generation renewable energy credits waiver. The ACC has not yet ruled on the GPP application. APS cannot predict the outcome of this proceeding.

Demand Side Management Adjustor Charge . The ACC Electric Energy Efficiency Standards require APS to submit a DSM Implementation Plan annually for review and approval by the ACC. Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism. See below for discussion of the LFCR.

On December 17, 2021, APS filed its 2022 D SM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM Plan requested a budget of $ 78.4 million and represents an increase of approximately $ 14 million in DSM spending above 2021. On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive.

On June 1, 2022, APS filed its 2023 Transportation Electrification Plan (“2023 TE Plan”). The 2023 TE Plan detailed APS’s efforts to support transportation electrification in Arizona, including the Take Charge AZ Pilot Program and customer education and outreach related to transportation electrification. Subsequently, APS filed an amended 2023 TE Plan on November 30, 2022, that included a request for a $ 5 million budget. On December 12, 2023, the ACC approved the 2023 TE Plan without including the

---

Take Charge AZ Program and its budget going forward, but allowed APS to complete projects already underway. Additionally, the ACC discontinued the residential EV SmartCharger rebate and approved modifications to the EV rate plan.

On November 30, 2022, APS filed its 2023 DSM Implementation Plan, which requested a budget of $ 88 million. On May 31, 2023, APS filed an amended 2023 DSM Implementation Plan. The amended plan maintained the originally proposed budget of $ 88 million. Subsequent to filing the amended 2023 DSM Implementation Plan and prior to the ACC approving it, on November 30, 2023, APS filed its 2024 DSM Implementation Plan. The 2024 DSM Implementation Plan requested a total budget of $ 91.5 million and incorporated all elements of the amended 2023 DSM Implementation Plan as well as the 2024 TE Implementation Plan. On April 26, 2024, APS filed an amendment to the 2024 DSM Implementation Plan. The amended 2024 DSM Implementation Plan includes an updated budget of $ 90.9 million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot. The ACC has not yet ruled on the amended 2024 DSM Implementation Plan. In a letter filed May 31, 2024, APS said it would not file a 2025 DSM Implementation Plan pending ACC review of the amended 2024 DSM Implementation Plan. APS cannot predict the outcome of this proceeding.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the 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 for 2024 and 2023 (dollars in thousands):

			Year Ended December 31,
			2024						2023
Balance at beginning of period			$	463,195					$	460,561
Deferred fuel and purchased power costs			250,288						549,877
Amounts charged to customers			( 425,886 )						( 547,243 )
Balance at end of period			$	287,597					$	463,195

On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $ 0.007544 per kWh, which consisted of a forward component of $( 0.004842 ) per kWh and a historical component of $ 0.012386 per kWh. The 2022 PSA rate was a $ 0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022.

On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021. The report contained an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities. The report found that APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity were reasonable and appropriate. The report included several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings. On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023.

On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. In this filing, APS also requested that one of three different options be adopted to address the growing undercollected PSA balance. On February 23, 2023, the ACC approved an overall PSA rate of $ 0.019074 per kWh, which consisted of a forward component of $( 0.005527 ) per kWh, a historical component of $ 0.013071 per kWh and a transition component of $ 0.011530 per kWh, that will continue until further notice of the ACC. The rate became effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24 -month period. On November 30, 2023, APS notified the ACC that it will be maintaining the current PSA rate of $ 0.019074 per kWh and an updated PSA adjustment schedule would not be filed at that time. In Decision No. 79293 in the 2022 Rate Case, the ACC approved a permanent increase in the annual PSA adjustor rate cap from $ 0.004 per kWh to $ 0.006 per kWh and a requirement that APS report to the ACC for possible action when the overall PSA balance reaches $ 100 million. As part of the 2022 Rate Case decision, the ACC also approved an overall PSA rate of $ 0.011977 per kWh, which consisted of a forward component of $( 0.012624 ) per kWh, a historical component of $ 0.013071 per kWh, and a transition component of $ 0.011530 per kWh. The overall PSA rate was reduced to offset an increase in base fuel prices. The rate became effective on March 8, 2024.

On November 27, 2024, APS filed its PSA rate for the PSA year beginning February 1, 2025. The overall PSA rate of $ 0.013977 per kWh consists of a forward component of $( 0.000281 ) per kWh, a

---

historical component of $ 0.008728 per kWh, and a transition component of $ 0.005530 . This overall PSA rate is an increase of $ 0.002 per kWh over the prior overall rate approved in the 2022 Rate Case decision, and it is below the annual PSA rate increase cap of $ 0.006 per kWh. On February 5, 2025, the ACC voted to approve this request, with a rate effective date of the first billing cycle in March 2025.

Environmental Improvement Surcharge. On March 5, 2024, the ACC approved the elimination of the EIS, and the surcharge is no longer in effect. The EIS permitted APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. APS’s February 1, 2023, EIS application requested an increase in the charge to $ 14.7 million, or $ 3.3 million over the prior-period charge. On March 10, 2023, APS filed an amended application requesting an EIS charge of $ 4.0 million, a decrease of $ 10.7 million from the February EIS request, and a decrease of $ 7.5 million from the prior-period charge. The revised 2023 EIS became effective with the first billing cycle in April 2023; however, with the elimination of the surcharge, it is no longer in effect, and any remaining amounts are being collected through base rates.

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, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $ 33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $ 6.4 million and retail customer rates would have decreased by approximately $ 26.6 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $ 2.4 million, resulting in a reduction to the residential rate and increases to commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022.

Effective June 1, 2023, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 34.7 million for the 12-month period beginning June 1, 2023, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $ 20.7 million and retail customer rates would have increased by approximately $ 14 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement decreased by $ 10 million, resulting in reductions to the residential

---

and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2023.

Effective June 1, 2024, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $ 27.4 million for the 12-month period beginning June 1, 2024 in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by approximately $ 16.6 million and retail customer rates would have increased by approximately $ 10.8 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC-approved balancing account, the retail revenue requirement increased by $ 8.8 million, resulting in an increase to residential and commercial rates over 3 MW and a decrease to commercial rates less than or equal to 3 MW. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2024.

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 February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $ 59.1 million (a $ 32.5 million increase from previous levels, which was inclusive of a $ 11.8 million balance from APS’s 2021 LFCR filing). On May 9, 2022, the ACC Staff filed its revised report and proposed order regarding APS’s 2022 LFCR adjustment, concluding that APS calculated the adjustment in accordance with its Plan of Administration. On May 18, 2022, the ACC approved the 2022 LFCR adjustment, with a rate effective date of June 1, 2022.

On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year. On September 5, 2023, APS filed an updated LFCR Plan of Administration, which was approved by ACC Staff on December 8, 2023. On July 31, 2023, APS filed its 2023 annual LFCR adjustment, requesting that the annual LFCR recovery amount be increased to $ 68.7 million (a $ 9.6 million increase from previous levels). On October 19, 2023, a request for intervention was filed, which was granted. Consistent with an October 25, 2023, Procedural Order, the parties met and conferred and conducted limited discovery. As a result of Decision No. 79293 in the 2022 Rate Case, APS transferred $ 27.1 million from the LFCR to base rates.

On March 8, 2024, APS filed conforming LFCR schedules to incorporate changes required as a result of Decision No. 79293 in the 2022 Rate Case. On April 9, 2024, the ACC approved the 2023 annual LFCR adjustment, with new rates effective in the first billing cycle of May 2024.

On June 5, 2024, APS filed a revised LFCR Plan of Administration in accordance with Decision No. 79293. The ACC approved the revised Plan of Administration on October 8, 2024.

---

On July 31, 2024, APS filed its 2024 annual LFCR adjustment, requesting that effective November 1, 2024, the annual LFCR recovery amount be increased to $ 49.6 million (an $ 8 million increase from previous levels). On December 3, 2024, the ACC approved the 2024 annual LFCR adjustment, with new rates effective in the first billing cycle of January 2025.

Tax Expense Adjustor Mechanism .  The TEAM helps address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. As part of the 2019 Rate Case decision, there remains small true up balances in the TEAM balancing account. In the 2022 Rate Case, these true up balances are being recovered and amortized through 2032.

Court Resolution Surcharge. The CRS mechanism permits APS to recover certain costs associated with investments and expenses for APS’s purchase and installation of 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, $ 26.2 million of which has been collected as of December 31, 2024, 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. See “2019 Retail Rate Case” above for more information.

Net Metering

The ACC’s decision from APS’s 2017 rate case (the “2017 Rate Case Decision”) provides that payments by utilities for energy exported to the grid from residential DG solar facilities will be determined using a Resource Comparison Proxy (“RCP”) methodology as determined in the ACC’s generic Value and Cost of Distributed Generation docket. RCP is a method that is based on the most recent five-year rolling average price that APS incurs for utility-scale solar photovoltaic projects. The price established by this RCP method is updated annually (between general retail rate cases) but cannot be decreased by more than 10 % per year.

On April 29, 2022, APS filed an application to decrease the RCP price from 9.4 cents per kWh, which had been in effect since October 1, 2021, to 8.46 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2022. On July 12, 2022, the ACC approved the RCP as filed.

On May 1, 2023, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 7.619 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2023. On August 25, 2023, the ACC approved the RCP as filed.

On May 1, 2024, APS filed an application for revisions to the RCP. This application would decrease the RCP price to 6.857 cents per kWh, reflecting a 10 % annual reduction, to become effective September 1, 2024. On August 13, 2024, the ACC approved the RCP as filed.

---

On October 11, 2023, the ACC voted to open a new general docket to hold a hearing to explore potential future changes to the 10 % annual reduction cap in the solar export rate paid by utilities to distributed solar customers for exports to the grid and the 10 -year rate lock period for those customers that were approved in the ACC’s Value and Cost of Distributed Generation Docket. A procedural conference was held on November 1, 2023, to discuss the process going forward. As a result of the procedural conference, ACC Staff issued a request for information to investigate the issues related to this matter. A status conference was held on March 20, 2024 to determine if ACC Staff is prepared to present a recommendation on this matter at that time. Stakeholders provided responses to the ACC Staff’s request for information on March 21, 2024. Another status conference took place on May 20, 2024 and ACC Staff issued a request for additional information to investigate the issues related to the matter on May 31, 2024. Stakeholders provided responses to the ACC Staff’s request for additional information on July 1, 2024, and on October 15, 2024, the ACC Staff filed a report finding that the RCP is working as intended and recommending no changes to the RCP at this time. The ACC Staff also recommended that the ACC close the docket without a hearing or further action. The ACC has not yet acted on the ACC Staff’s recommendation, and APS cannot predict the outcome of this matter.

Energy Modernization Plan

On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the Renewable Energy Standard and Tariff, and Electric Energy Efficiency Standards. On January 9, 2024, the ACC approved a rulemaking process for this matter. During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current Electric Energy Efficiency and Renewable Energy Standard rules during the rulemaking process. On August 21, 2024, the ACC Staff filed separate reports for each set of rules, including its recommendations to repeal the Electric Energy Efficiency and Renewable Energy Standard rules along with required preliminary economic, small business, and consumer impact statements. APS and other interested parties have filed comments about the ACC Staff reports. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop triennial 15-year IRPs which describe how the utility plans to serve customer load in the plan time frame. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In February 2022, the ACC acknowledged APS’s 2020 IRP filed on June 26, 2020. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030.

On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc. filed a joint request for an extension to file the IRPs from August 1, 2023, to November 1, 2023. On June 21, 2023, the ACC granted the extension. As a result, APS filed its 2023 IRP on November 1, 2023. On January 31, 2024, stakeholders filed comments regarding the IRP, and APS filed its response to stakeholder comments on May 31, 2024. On July 31, 2024, the ACC held an IRP workshop where utilities and stakeholders presented on the 2023 IRPs. On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate resource adequacy prior to exiting Four Corners as well as analysis of impacts from western market participation and planned resource requirements in the next IRP. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

---

Equity Infusions

On October 27, 2023, APS filed a notice of intent to increase Pinnacle West’s equity in APS in 2024. APS sought approval to receive from Pinnacle West in 2024 up to $ 500 million in additional equity infusions above the previously authorized limit of $ 150 million annually. The ACC approved the increased equity infusion limit for 2024 on January 9, 2024.

On April 19, 2024, APS submitted a request to the ACC to permanently modify Pinnacle West’s permitted yearly equity infusions to equal up to 2.5 % of APS’s consolidated assets each calendar year on a three-year rolling average basis. On December 17, 2024, the ACC issued a financing order that approved an annual equity infusion allowance of 2.5 % of APS’s consolidated assets on a three-year rolling average basis.

Public Utility Regulatory Policies Act

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis.

Residential Electric Utility Customer Service Disconnections

In accordance with the ACC’s service disconnection rules, APS uses a calendar-based method to suspend the disconnection of customers for nonpayment from June 1 through October 15 each year (“Annual Disconnection Moratorium”). Pursuant to an ACC order, customers with past due balances of $ 75 or greater as of approximately one month prior to the end of the Annual Disconnection Moratorium are automatically placed on six-month payment arrangements. In addition, APS voluntarily began waiving late payment fees of its customers (“Late Fee Waivers”) on March 13, 2020. Effective February 1, 2023, late payment fees for residential customers were reinstated. Late payment fees for commercial and industrial customers were reinstated effective May 1, 2022. Since the suspensions and moratoriums on disconnections began, APS has experienced an increase in bad debt expense and the related write-offs of delinquent customer accounts.

Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. In April 2022, the Arizona Legislature passed, and the Governor signed a bill that repealed the electric deregulation law that

---

had been in place in Arizona since 1998. On August 27, 2024, the ACC administratively closed this docket due to inactivity and obsolescence.

Four Corners SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. The SCR Adjustment request provided that there would be a $ 67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff’s recommendation of a lower annual revenue impact of approximately $ 58.5 million. The Administrative Law Judge issued a ROO finding that the costs for the SCR project were prudently incurred and recommending authorization of the $ 58.5 million annual revenue requirement related to the installation and operation of the SCRs. The ACC did not issue a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 Rate Case filing with the ACC.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $ 194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $ 215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $ 215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. On March 6, 2023, the Court of Appeals issued its order in the matter, vacating the ACC’s disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rules and the order of the Court of Appeals. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See above for further discussion on the 2019 Rate Case decision.

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the 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 is required to cease burning coal at its remaining Cholla units by April 2025.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. APS is allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs, $ 28.1 million as

---

of December 31, 2024, in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. In accordance with the 2019 Rate Case decision, the regulatory asset is being amortized through 2033.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of the remaining Cholla units. This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025. APS cannot predict the outcome of this matter.

Navajo Plant

The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations. In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset.

APS has been recovering a return on and of the net book value of its interest in the Navajo plant in base rates over its previously estimated life through 2026. Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant, $ 33.4 million as of December 31, 2024, in addition to a return on the net book value, with the exception of 15 % of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset, $ 7.9 million as of December 31, 2024. 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. APS cannot predict the outcome of this matter.

---

Regulatory Assets and Liabilities

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

									December 31,
			Amortization Through						2024						2023
Pension			(a)						$	750,976					$	696,476
Deferred fuel and purchased power (b) (c)			2025						287,597						463,195
Income taxes — AFUDC equity			2054						192,936						189,058
Ocotillo deferral			2034						114,775						128,636
SCR deferral (e)			2038						83,123						89,477
Lease incentives			(g)						70,541						46,615
Retired power plant costs			2033						68,380						83,536
Deferred fuel and purchased power — mark-to-market (Note 15)			2027						42,275						120,214
FERC Transmission true up			2026						35,159						616
Income taxes — investment tax credit basis adjustment			2056						34,834						34,230
Deferred compensation			2036						33,108						33,972
Deferred property taxes			2027						23,918						32,488
Palo Verde VIEs (Note 17)			2046						20,611						20,772
Power supply adjustor - interest			2025						11,525						19,416
Active Union Medical Trust			(f)						9,673						12,747
Mead-Phoenix transmission line contributions in aid of construction (“CIAC”)			2050						8,384						8,716
Navajo coal reclamation			2026						7,905						10,883
Loss on reacquired debt			2038						6,682						7,965
Tax expense adjustor mechanism (b)			2031						4,534						5,190
Four Corners cost deferral			2024						—						7,922
Other			Various						3,522						3,912
Total regulatory assets (d)									$	1,810,458					$	2,016,036
Less: current regulatory assets									$	420,969					$	625,757
Total non-current regulatory assets									$	1,389,489					$	1,390,279

(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 OCI and result in lower future revenues.  As a result of the 2019 Rate Case decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. The 2022 Rate Case decision allows for the full return on the pension asset in rate base. See Note 7 for further discussion.

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

(c) Subject to a carrying charge.

(d) There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

(e) See “Four Corners SCR Cost Recovery” discussion above.

(f) Collected in retail rates.

(g) Amortization periods vary based on specific terms of lease contract.

---

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

									December 31,
			Amortization Through						2024						2023
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)			2046						$	888,896					$	930,344
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)			2058						207,400						214,667
Asset retirement obligations and removal costs			(d)						358,403						486,751
Other postretirement benefits			(c)						238,113						226,726
Four Corners coal reclamation			2038						77,532						68,521
Renewable energy standard (b)			2025						68,523						60,667
Income taxes — deferred investment tax credit			2056						66,327						55,917
Income taxes — change in rates			2053						59,133						43,251
Spent nuclear fuel			2027						26,818						33,154
Demand side management (b)			2025						23,927						14,374
Sundance maintenance			2031						23,086						19,989
TCA Balancing Account (b)			2026						14,834						3,425
Property tax deferral			2027						4,785						10,850
Tax expense adjustor mechanism (b)			2032						4,343						4,835
Other			Various						113						2,317
Total regulatory liabilities									$	2,062,233					$	2,175,788
Less: current regulatory liabilities									$	206,955					$	209,923
Total non-current regulatory liabilities									$	1,855,278					$	1,965,865

(a) For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

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

(c) See Note 7.

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

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the Statements of Income.

---

On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $ 23 million of investment tax credits from the BCE Los Alamitos project for $ 21 million. See Note 20 for more information about the BCE Sale.

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. Energy produced and sold by APS from Palo Verde between 2024 and 2032 is eligible for this credit subject to a credit phase out based upon APS’s gross receipts from nuclear sales. 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. Without such guidance, the Company is unable to accurately determine the benefit the Nuclear PTC may provide. Due to the lack of guidance, no income tax benefits have been recognized related to the Nuclear PTC as of December 31, 2024.

Net income associated with the Captive and Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 17 for additional details related to Palo Verde sale leaseback VIEs.

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			2024						2023						2022						2024						2023						2022
Total unrecognized tax benefits, January 1			$	44,274					$	43,097					$	45,086					$	44,274					$	43,097					$	45,086
Additions for tax positions of the current year			1,271						1,473						1,399						1,271						1,473						1,399
Additions for tax positions of prior years			2,031						419						2,069						2,031						419						2,069
Reductions for tax positions of prior years for:
Changes in judgment			( 2,043 )						661						( 3,495 )						( 2,043 )						661						( 3,495 )
Settlements with taxing authorities			—						—						—						—						—						—
Lapses of applicable statute of limitations			( 1,184 )						( 1,376 )						( 1,962 )						( 1,184 )						( 1,376 )						( 1,962 )
Total unrecognized tax benefits, December 31			$	44,349					$	44,274					$	43,097					$	44,349					$	44,274					$	43,097

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			2024						2023						2022						2024						2023						2022
Tax positions, that if recognized, would decrease our effective tax rate			$	27,899					$	28,762					$	28,246					$	27,899					$	28,762					$	28,246

As of the balance sheet date, the tax year ended December 31, 2021, and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2020.

---

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			2024						2023						2022						2024						2023						2022
Unrecognized tax benefit interest expense/(benefit) recognized			$	2,743					$	452					$	( 139 )					$	2,743					$	452					$	( 139 )

Following are the total amounts of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			2024						2023						2022						2024						2023						2022
Unrecognized tax benefit interest accrued			$	4,376					$	1,633					$	1,181					$	4,376					$	1,633					$	1,181

Additionally, as of December 31, 2024, we have recognized approximately $ 2.1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			Year Ended December 31,																		Year Ended December 31,
			2024						2023						2022						2024						2023						2022
Current:
Federal			$	137,342					$	21,272					$	35,617					$	165,653					$	26,405					$	103,349
State			2,392						2,854						1,950						26,054						1,027						161
Total current			139,734						24,126						37,567						191,707						27,432						103,510
Deferred:
Federal			( 53,228 )						37,273						23,693						( 69,075 )						44,922						( 31,860 )
State			24,023						15,513						13,567						4,361						21,830						19,150
Total deferred			( 29,205 )						52,786						37,260						( 64,714 )						66,752						( 12,710 )
Income tax expense/(benefit)			$	110,529					$	76,912					$	74,827					$	126,993					$	94,184					$	90,800

---

The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):

			Pinnacle West Consolidated																		APS Consolidated
			Year Ended December 31,																		Year Ended December 31,
			2024						2023						2022						2024						2023						2022
Federal income tax expense at statutory rate			$	154,677					$	125,095					$	120,887					$	165,090					$	138,337					$	132,920
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit			24,218						18,024						17,740						25,639						19,832						19,000
State income tax credits net of federal income tax benefit			( 3,349 )						( 3,513 )						( 5,482 )						( 1,611 )						( 1,775 )						( 3,744 )
Excess deferred income taxes — Tax Cuts and Jobs Act			( 36,559 )						( 36,558 )						( 36,241 )						( 36,559 )						( 36,558 )						( 36,241 )
Allowance for equity funds used during construction (Note 1)			( 2,545 )						( 5,964 )						( 4,629 )						( 2,545 )						( 5,964 )						( 4,629 )
Palo Verde VIE noncontrolling interest (Note 17)			( 3,617 )						( 3,617 )						( 3,617 )						( 3,617 )						( 3,617 )						( 3,617 )
Investment tax credit amortization			( 9,425 )						( 9,495 )						( 5,608 )						( 9,425 )						( 9,495 )						( 5,608 )
Federal production tax credit			( 15,206 )						( 8,441 )						( 3,146 )						( 12,110 )						( 5,460 )						—
Other federal income tax credits			( 3,881 )						( 3,453 )						( 7,721 )						( 1,551 )						( 2,803 )						( 7,721 )
Other			6,216						4,834						2,644						3,682						1,687						440
Income tax expense/(benefit)			$	110,529					$	76,912					$	74,827					$	126,993					$	94,184					$	90,800

---

The components of the net deferred income tax liability were as follows (dollars in thousands):

			Pinnacle West Consolidated												APS Consolidated
			December 31,												December 31,
			2024						2023						2024						2023
DEFERRED TAX ASSETS
Risk management activities			$	14,539					$	31,411					$	14,539					$	31,411
Regulatory liabilities:
Excess deferred income taxes — Tax Cuts and Jobs Act			271,004						283,161						271,004						283,161
Asset retirement obligation and removal costs			81,308						113,312						81,308						113,312
Unamortized investment tax credits			66,327						68,521						66,327						68,521
Other postretirement benefits			58,862						56,070						58,862						56,070
Other			47,671						39,857						47,671						39,857
Operating lease liabilities			400,771						316,067						400,442						315,670
Pension liabilities			39,070						33,294						36,100						29,918
Coal reclamation liabilities			42,391						45,505						42,391						45,505
Renewable energy incentives			14,571						17,261						14,571						17,261
Credit and loss carryforwards			7,682						43,940						—						3,031
Employee benefit liabilities			57,853						49,222						56,561						48,551
Other			44,412						28,643						44,412						29,314
Total deferred tax assets			1,146,461						1,126,264						1,134,188						1,081,582
DEFERRED TAX LIABILITIES
Plant-related			( 2,562,990 )						( 2,572,495 )						( 2,562,990 )						( 2,572,495 )
Risk management activities			( 4,089 )						( 1,682 )						( 4,089 )						( 1,682 )
Pension and other postretirement assets			( 83,401 )						( 78,853 )						( 82,925 )						( 78,297 )
Other special use funds			( 55,146 )						( 56,550 )						( 55,146 )						( 56,550 )
Operating lease right-of-use assets			( 400,771 )						( 316,067 )						( 400,443 )						( 315,670 )
Regulatory assets:
Allowance for equity funds used during construction			( 47,694 )						( 46,754 )						( 47,694 )						( 46,754 )
Deferred fuel and purchased power			( 84,393 )						( 149,078 )						( 84,393 )						( 149,078 )
Pension benefits			( 185,641 )						( 172,239 )						( 185,641 )						( 172,239 )
Ocotillo deferral			( 28,372 )						( 31,812 )						( 28,372 )						( 31,812 )
SCR deferral			( 20,548 )						( 22,128 )						( 20,548 )						( 22,128 )
Retired power plant costs			( 16,904 )						( 20,659 )						( 16,904 )						( 20,659 )
Other			( 57,602 )						( 38,320 )						( 57,602 )						( 38,320 )
Other			( 43,383 )						( 36,107 )						( 7,378 )						( 7,595 )
Total deferred tax liabilities			( 3,590,934 )						( 3,542,744 )						( 3,554,125 )						( 3,513,279 )
Deferred income taxes — net			$	( 2,444,473 )					$	( 2,416,480 )					$	( 2,419,937 )					$	( 2,431,697 )

As of December 31, 2024, Pinnacle West consolidated deferred tax assets for credit and loss carryforwards relate to federal and state credit carryforwards, net of federal benefit, of $ 12 million, which first begin to expire in 2029. Pinnacle West consolidated credit and loss carryforwards amount above has been reduced by $ 4 million of unrecognized tax benefits.

---

As of December 31, 2024, APS consolidated does not have any deferred tax assets for credit and loss carryforwards relating to federal or state carryforwards due to APS utilizing all available federal and state credits in 2024.

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.

The table below presents the consolidated credit and term loan facilities and the amounts available and outstanding (dollars in thousands):

			December 31, 2024												December 31, 2023
			Pinnacle West			APS			Total						Pinnacle West			APS			Total
Commitments under Credit and Term Loan Facilities			$	400,000		$	1,650,000		$	2,050,000					$	200,000		$	1,250,000		$	1,450,000
Outstanding short-term borrowings			( 228,550 )			( 339,900 )			( 568,450 )						( 76,650 )			( 532,850 )			( 609,500 )
Amount of Credit and Term Loan Facilities Available			$	171,450		$	1,310,100		$	1,481,550					$	123,350		$	717,150		$	840,500
Weighted-Average Commitment Fees			0.225 %			0.175 %									0.170 %			0.120 %

Pinnacle West

On August 2, 2024, Pinnacle West amended its $ 200 million revolving credit facility, extending the maturity date from April 10, 2028 to April 10, 2029, and providing a mechanism to either update the Sustainability Table (as defined in the Pinnacle West revolving credit facility), which provides for a sustainability-linked pricing feature, or, in certain circumstances, terminate the sustainability-linked pricing feature for the final year. Pinnacle West has the option to increase the amount of the facility up to a total of $ 300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $ 200 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2024, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under its credit facility, and $ 29 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2024, was 4.58 %.

On December 5, 2024, Pinnacle West entered into an agreement with a new 364 -day $ 200 million term loan facility that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus 0.95 % per annum. On December 20, 2024, Pinnacle West drew the full amount of $ 200 million. On December 20, 2024, Pinnacle West repaid $ 200 million of the Pinnacle West term loan which matured in December 2024.

---

APS

On August 2, 2024, APS amended its $ 1.25 billion revolving credit facility, extending the maturity date from April 10, 2028 to April 10, 2029, and providing a mechanism to either update the Sustainability Table (as defined in the APS revolving credit facility), which provides for a sustainability-linked pricing feature, or, in certain circumstances, terminate the sustainability-linked pricing feature for the final year. APS has the option to increase the amount of the facility by up to a maximum of $ 400 million , for a total of $ 1.65 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support APS’s general corporate purposes, including support for APS’s commercial paper program, which was incr eased from $ 750 million to $ 1 billion on April 10, 2023, for bank borrowings or for issuances of letters of credit. At December 31, 2024, APS had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility, and $ 340 million of outstanding commercial paper borrowings. The weighted-average interest rate for the outstanding borrowings on December 31, 2024, was 4.62 %.

On December 12, 2023, APS entered into an agreement for a new 364 -day $ 350 million term loan facility that matured on December 10, 2024. Borrowings under the facility boar interest at SOFR plus 1.0 % per annum. On February 9, 2024, APS drew the full amount of $ 350 million, which APS subsequently paid off in full on June 10, 2024.

On December 5, 2024, APS entered into a $ 400 million 364 -Day Term Loan Agreement that matures on December 4, 2025. Borrowings under the facility bear interest at SOFR plus 0.90 % per annum. As of the date of this report, APS has not drawn on this term loan.

See “Financial Assurances” in Note 10 for a discussion of other outst anding letters of credit.

Debt Provisions

---

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding (dollars in thousands):

			Maturity						Interest						December 31,
			Dates (a)						Rates						2024						2023
APS
Pollution control bonds:
Variable			2029						(b)						$	163,975					$	163,975
Total pollution control bonds															163,975						163,975
Senior unsecured notes			2025-2050						2.20 %- 6.88 %						7,380,000						7,180,000
Unamortized discount															( 14,252 )						( 14,197 )
Unamortized premium															9,955						11,162
Unamortized debt issuance cost															( 48,800 )						( 49,049 )
Total APS long-term debt															7,490,878						7,291,891
Less current maturities															300,000						250,000
Total APS long-term debt less current maturities															7,190,878						7,041,891
Pinnacle West
Senior unsecured notes			2025-2027						1.30 %- 4.75 %						1,025,000						500,000
Floating rate note			2026						(c)						350,000						—
Term loans			2024						(d)						—						625,000
Unamortized discount															( 5 )						( 15 )
Unamortized debt issuance cost															( 7,225 )						( 1,254 )
Total Pinnacle West long-term debt															1,367,770						1,123,731
Less current maturities															500,000						625,000
Total Pinnacle West long-term debt less current maturities															867,770						498,731
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES															$	8,058,648					$	7,540,622

(a)    This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b)    The weighted-average interest rate for the variable rate pollution control bonds was 4.01 % at December 31, 2024, and 4.11 % at December 31, 2023.

(c)    The weighted-average interest rate was 5.88 % at December 31, 2024, and was not applicable at December 31, 2023. See additional details below.

(d)    The weighted-average interest rate was not applicable at December 31, 2024, and was 6.20 % at December 31, 2023. See additional details below.

---

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

Year						Pinnacle West Consolidated						APS Consolidated
2025						$	800,000					$	300,000
2026						600,000						250,000
2027						825,000						300,000
2028						—						—
2029						568,975						568,975
Thereafter						6,125,000						6,125,000
Total						$	8,918,975					$	7,543,975

Debt Fair Value

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

			As of December 31, 2024												As of December 31, 2023
			Carrying Amount						Fair Value						Carrying Amount						Fair Value
Pinnacle West			$	1,367,770					$	1,393,744					$	1,123,731					$	1,095,935
APS			7,490,878						6,525,248						7,291,891						6,459,718
Total			$	8,858,648					$	7,918,992					$	8,415,622					$	7,555,653

Credit Facilities and Debt and Equity Issuances

Pinnacle West

On December 16, 2022, Pinnacle West entered into a $ 175 million term loan facility that matured on December 16, 2024. The proceeds were received on January 6, 2023, and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 6, 2023. On June 10, 2024 Pinnacle West repaid the full $ 175 million term loan, that matured on December 16, 2024.

On February 28, 2024, Pinnacle West entered into equity forward sale agreements (the “February 2024 Forward Sale Agreements”), which may be settled with Pinnacle West common stock or cash. In December 2024, Pinnacle West partially settled the 2024 Forward Sale Agreements by issuing 5,377,115 shares of common stock and receiving net proceeds of $ 345 million . The proceeds were recorded in equity. At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock, which would have provided cash liquidity to Pinnacle West of approximately $ 377 million. See Note 13.

On November 8, 2024, Pinnacle West entered into an equity forward sale agreement under the ATM program (the “November 2024 ATM Forward Sale Agreement”), which may be settled with Pinnacle West common stock or cash. At December 31, 2024, Pinnacle West could have settled the November 2024 ATM Forward Sale Agreement with the issuance of 552,833 shares of common stock, which would have provided cash liquidity to Pinnacle West of approximately $ 50 million. See Note 13.

---

Convertible Senior 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. The Convertible Notes bear interest at a fixed rate of 4.75 % per year, payable semiannually in arrears on June 15 and December 15 of each year, beginning on December 15, 2024. Proceeds from the Convertible Notes were used to repay APS’s 364 -day $ 350 million term loan facility that matured on December 10, 2024 and commercial paper borrowings.

Prior to March 15, 2027, the holders of the Convertible Notes may elect at their option to convert all or any portion of their Convertible Notes under the following limited circumstances:

• during any calendar quarter (and only during such calendar quarter), if the sale price of Pinnacle West common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter, is greater than or equal to 130 % of the conversion price on each applicable trading day;

• during the five business day period after any 10 consecutive trading day period (“Measurement Period”) in which the trading price per $1,000 principal amount of Convertible Notes for each trading day of the Measurement Period was less than 98 % of the product of the last reported sale price of Pinnacle West common stock and the conversion rate on such trading day; or

• upon the occurrence of certain corporate events, as defined in the Convertible Notes’ indenture.

On or after March 15, 2027, until the maturity date, the holders of the Convertible Notes may elect at their option to convert all or any portion of their notes. Upon conversion, Pinnacle West will pay cash up to the aggregate principal amount of the Convertible Notes converted and at Pinnacle West’s sole discretion, pay or deliver cash, shares of Pinnacle West common stock or a combination of both, in respect 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 of Pinnacle West’s common stock. 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 December 31, 2024, the conditions allowing holders to convert their Convertible Notes were not met, and as a result, the Convertible Notes were classified as long term debt on Pinnacle West’s Consolidated Balance Sheets with a carrying amount of $ 525 million, including unamortized debt issuance costs of $ 8 million. The estimated fair value of the Convertible Notes as of December 31, 2024 was $ 552 million (Level 2 within the fair value hierarchy).

---

As of December 31, 2024, based on Pinnacle West’s average stock price and the relevant terms of the Convertible Notes, there were no shares of Pinnacles West’s common stock included in basic or diluted EPS relating to the potential conversion of the Convertible Notes. See Note 13.

Floating Rate Notes. In June 2024, Pinnacle West completed the sale of $ 350 million Floating Rate Notes due 2026 (the “Floating Rate Notes”). The Floating Rate Notes are senior unsecured obligations of Pinnacle West and will mature on June 10, 2026. The Floating Rate Notes bear a variable interest rate of Compounded SOFR (as defined in the Fifth Supplemental Indenture dated as of June 10, 2024) plus 82 basis points per year. Proceeds were used to repay a portion of Pinnacle West’s $ 450 million term loan that matured in December 2024 and the full amount of Pinnacle West’s $ 175 million term loan that matured in December 2024.

On June 10, 2024, Pinnacle West repaid $ 250 million of its $ 450 million term loan which matured in December 2024. On December 20, 2024, Pinnacle West repaid the remaining $ 200 million of the term loan.

On June 10, 2024 Pinnacle West repaid the full $ 175 million term loan, that matured on December 16, 2024.

APS

APS was previously authorized to receive up to $ 150 million annually in equity infusions from Pinnacle West without seeking ACC approval. In 2023, APS sought approval for an additional $ 500 million in equity infusions and received approval in early 2024. Subsequently, APS requested and the ACC issued a new financing order that approved a limit on yearly equity infusions 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.

On June 12, 2024, Pinnacle West contributed $ 450 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness. On December 23, 2024, Pinnacle West contributed $ 345 million into APS in the form of an equity infusion. APS used this contribution to repay a portion of commercial paper borrowings and for other general corporate purposes.

On May 9, 2024, APS issued $ 450 million of 5.7 % senior unsecured notes that mature August 15, 2034. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper and for general corporate purposes.

On June 17, 2024, APS repaid its $ 250 million 3.35 % senior unsecured notes at maturity from commercial paper borrowings.

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

BCE

On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for the development of a 31 megawatt (“MW”) solar and 20 megawatt hour (“MWh”) battery storage project in Los Alamitos, California (“Los Alamitos”). The credit

---

agreement consisted of an equity bridge loan facility, a non-recourse construction facility, a letter of credit facility, and a related interest rate swap. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement with Ameresco, Inc. (“Ameresco”), pursuant to which we agreed to sell all our equity interest in BCE to Ameresco (the “BCE Sale”). See Note 20. As a part of the BCE Sale closing, the $ 36 million construction facility, the letter of credit facility, and the interest rate swap were transferred to Ameresco. On August 4, 2023, concurrent with the BCE Sale, Pinnacle West paid in full the outstanding $ 31 million equity bridge loan balance. As of December 31, 2024, there is no outstanding balance on our Consolidated Balance Sheets relating to this credit agreement.

On April 18, 2023, and on December 29, 2023, Pinnacle West issued performance guarantees in connection with BCE’s Kūpono Solar investment project financing. BCE held an equity method investment relating to the Kūpono Solar project that was included in the BCE Sale relating to the stage of the BCE Sale that closed on January 12, 2024. The performance guarantees did not transfer in the BCE Sale, and Pinnacle West continues to retain these performance guarantees. See Note 10.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65 %.  At December 31, 2024, the ratio was approximately 59 % for Pinnacle West and 49 % for APS.  Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

On April 19, 2024, APS submitted an application to the ACC requesting to increase the long-term debt limit from $ 8.0 billion to $ 9.5 billion and to increase Pinnacle West’s permitted yearly equity infusions to equal up to 2.5 % of APS’s consolidated assets each calendar year on a three-year rolling average basis. On December 17, 2024, the ACC issued a financing order approving the increase of the long-term debt limit to $ 9.5 billion and the permitted yearly equity infusions to 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

---

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries.  All new employees participate in the account balance plan.  Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant.  The pension plan covers nearly all employees.  The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.  Our employees do not contribute directly to the plans.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries.  These plans provide medical and life insurance benefits to retired employees.  Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.  For the medical insurance plan, retirees make contributions to cover a portion of the plan costs.  For the life insurance plan, retirees do not make contributions.  We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.  See Note 12 for further discussion of how fair values are determined.  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory liability. Our retail rates provide for the inclusion of annual benefit expense, which allows for recovery or return of this regulatory asset/liability. S ee Note 3.

---

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

						Pension Plans																		Other Benefits Plans
						2024						2023						2022						2024						2023						2022
Service cost-benefits earned during the period						$	43,641					$	39,461					$	55,473					$	9,955					$	8,567					$	16,470
Non-service costs (credits):
Interest cost on benefit obligation						148,643						153,561						107,492						22,169						22,509						17,491
Expected return on plan assets						( 188,651 )						( 182,938 )						( 185,775 )						( 46,834 )						( 43,486 )						( 46,042 )
Amortization of:
Prior service credit (a)						—						—						—						( 37,789 )						( 37,789 )						( 37,789 )
Net actuarial loss (gain)						41,915						38,420						17,515						( 8,676 )						( 9,614 )						( 12,835 )
Net periodic benefit costs (credits)						$	45,548					$	48,504					$	( 5,295 )					$	( 61,175 )					$	( 59,813 )					$	( 62,705 )
Portion of costs (credits) charged to expense						$	23,652					$	27,029					$	( 16,431 )					$	( 45,557 )					$	( 43,408 )					$	( 45,042 )

(a)    Prior-service costs or credits reflect the impact of modifications to the pension or postretirement plan benefits. The impact of these modifications is amortized over a period which reflects the demographics of the impacted population. In 2014, Pinnacle West made changes to the postretirement benefits offered to Medicare eligible retirees which resulted in prior-service credits. We have been amortizing these prior-serviced credits since 2015 with the last full-year amortization occurring in 2024.

The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):

			Pension Plans												Other Benefits Plans
			2024						2023						2024						2023
Change in Benefit Obligation
Benefit obligation at January 1			$	2,908,063					$	2,809,529					$	430,434					$	409,461
Service cost			43,641						39,461						9,955						8,567
Interest cost			148,643						153,561						22,169						22,509
Benefit payments			( 216,238 )						( 210,737 )						( 30,516 )						( 30,784 )
Actuarial (gain) loss			( 91,800 )						116,249						( 71,952 )						20,681
Benefit obligation at December 31			2,792,309						2,908,063						360,090						430,434
Change in Plan Assets
Fair value of plan assets at January 1			2,835,549						2,829,485						696,494						652,287
Actual return on plan assets			4,518						199,098						32,816						67,317
Benefit payments			( 200,205 )						( 193,034 )						( 27,118 )						( 23,110 )
Fair value of plan assets at December 31			2,639,862						2,835,549						702,192						696,494
Funded (Underfunded) Status at December 31			$	( 152,447 )					$	( 72,514 )					$	342,102					$	266,060

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):

			As of December 31,
			2024						2023
Accumulated benefit obligation			$	113,541					$	123,701
Fair value of plan assets			—						—

---

The Pinnacle West Capital Corporation Retirement Plan is more than 100 % funded on an accumulated benefit obligation basis at December 31, 2024, and December 31, 2023, therefore, the only pension plan with an accumulated benefit obligation in excess of plan assets in 2024 and 2023 is a non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):

			As of December 31,
			2024						2023
Projected benefit obligation			$	2,792,309					$	129,891
Fair value of plan assets			2,639,862						—

The Pinnacle West Capital Corporation Retirement Plan, on a projected benefit obligation basis, was 99 % funded at December 31, 2024 and 102 % funded at December 31, 2023. For 2024, we included both the projected benefit obligation and the fair value of plan assets for our qualified pension plan and a non-qualified supplemental excess benefit retirement plan. In 2023, the only plan that was underfunded was the non-qualified supplemental excess benefit retirement plan.

The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):

			Pension Plans												Other Benefits Plans
			2024						2023						2024						2023
Noncurrent asset			$	—					$	57,378					$	342,102					$	266,060
Current liability			( 13,130 )						( 17,190 )						—						—
Noncurrent liability			( 139,317 )						( 112,702 )						—						—
Net amount recognized (funded status)			$	( 152,447 )					$	( 72,514 )					$	342,102					$	266,060

The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 2024, and 2023 (dollars in thousands):

			Pension Plans												Other Benefits Plans
			2024						2023						2024						2023
Net actuarial loss (gain)			$	793,421					$	743,003					$	( 237,889 )					$	( 188,630 )
Prior service credit			—						—						( 1,265 )						( 39,054 )
APS’s portion recorded as a regulatory (asset) liability			( 750,976 )						( 696,476 )						238,113						226,726
Income tax expense (benefit)			( 10,354 )						( 11,506 )						611						691
Accumulated other comprehensive loss (gain)			$	32,091					$	35,021					$	( 430 )					$	( 267 )

---

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:

			Benefit Obligations As of December 31,												Benefit Costs Year Ended December 31,
			2024						2023						2024						2023						2022
Discount rate – pension plans			5.68		%				5.21		%				5.21		%				5.56		%				2.92		%
Discount rate – other benefits plans			5.71		%				5.23		%				5.23		%				5.58		%				2.98		%
Rate of compensation increase			4.50		%				4.52		%				4.52		%				4.57		%				4.00		%
Expected long-term return on plan assets - pension plans			N/A						N/A						6.90		%				6.70		%				5.00		%
Expected long-term return on plan assets - other benefit plans			N/A						N/A						6.85		%				6.80		%				5.35		%
Initial healthcare cost trend rate (pre-65 participants)			6.50		%				6.25		%				6.25		%				6.50		%				6.00		%
Ultimate healthcare cost trend rate (pre-65 participants)			4.50		%				4.75		%				4.75		%				4.75		%				4.75		%
Number of years to ultimate trend rate (pre-65 participants)			6						5						4						5						3
Initial healthcare cost trend rate (post-65 participants)			1.00		%				2.00		%				2.00		%				2.00		%				2.00		%
Ultimate healthcare cost trend rate (post-65 participants)			—		%				2.00		%				2.00		%				2.00		%				2.00		%
Interest crediting rate – cash balance pension plans			4.66		%				4.54		%				4.54		%				4.50		%				4.50		%

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.  For 2025, we are assuming a 7.05 % long-term rate of return for pension assets and 7.15 % (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.

Plan Assets

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”).  The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.  To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-seeking assets.  The target allocation between return-seeking and long-term fixed income assets is defined in the IPS.  The plan’s funded status is reviewed on at least a monthly basis.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates.  Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government agencies, U.S. Treasury futures contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, and other instruments.

---

Return-seeking assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.  Return-seeking assets are composed of U.S. equities, international equities, and alternative investments.  International equities include investments in both developed and emerging markets.  Alternative investments may include investments in real estate, private debt and various other strategies.  The plan may also hold investments in return-seeking assets by holding securities in partnerships, common and collective trusts, and mutual funds.

Based on the IPS, the target and actual allocation for the pension plan at December 31, 2024, are as follows:

			Target Allocation						Actual Allocation
Long-term fixed income assets			80		%				79		%
Return-seeking assets			20		%				21		%
Total			100		%				100		%

The permissible range is within +/-5% of the target allocation shown in the above table, and also considers the plan’s funded status.

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-seeking assets:

			Target Allocation
Equities in US and other developed markets			12		%
Equities in emerging markets			4		%
Alternative investments			4		%
Total			20		%

The pension plan IPS does not provide for a specific mix of long-term fixed income assets but does expect the average credit quality of such assets to be investment grade.

As of December 31, 2024, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2024:

			Actual Allocation
Long-term fixed income assets			61		%
Return-seeking assets			39		%
Total			100		%

See Note 12 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts.  Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades and are classified as Level 1.  U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market

---

prices and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity, and credit quality.  These instruments are classified as Level 2.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a net asset value (“NAV”) concept or its equivalent. Mutual funds, which includes exchange traded funds (“ETFs”), are classified as Level 1, and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  The trust’s shares are offered to a limited group of investors and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships’ underlying assets. The plan’s partnerships holdings relate to investments in high-yield fixed income instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $ 50 million to these partnerships; as of December 31, 2024, approximately $ 38 million of these commitments have been funded.

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.  We have internal control procedures to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

---

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2024, by asset category, are as follows (dollars in thousands):

			Level 1						Level 2						Other (a)						Total
Pension Plan:
Cash and cash equivalents			$	9,055					$	—					$	—					$	9,055
Fixed income securities:
Corporate			—						1,325,833						—						1,325,833
U.S. Treasury			561,317						—						—						561,317
Other (b)			—						133,254						—						133,254
Common stock equities (c)			74,939						—						—						74,939
Mutual funds (d)			102,722						—						—						102,722
Common and collective trusts:
Equities			—						—						244,734						244,734
Real estate			—						—						127,397						127,397
Other (e)			—						—						60,611						60,611
Total			$	748,033					$	1,459,087					$	432,742					$	2,639,862
Other Benefits:
Cash and cash equivalents			$	840					$	—					$	—					$	840
Fixed income securities:
Corporate			—						186,435						—						186,435
U.S. Treasury			204,274						—						—						204,274
Other (b)			—						12,585						—						12,585
Common stock equities (c)			89,685						—						—						89,685
Mutual funds (d)			23,415						—						—						23,415
Common and collective trusts:
Equities			—						—						140,178						140,178
Real estate			—						—						19,474						19,474
Other (e)			19,145						—						6,161						25,306
Total			$	337,359					$	199,020					$	165,813					$	702,192

(a) These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.

(b) This category consists primarily of debt securities issued by municipalities and asset backed securities.

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in international common stock equities.

(e) Primarily relates to short-term investment funds and includes plan receivables and payables.

---

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2023, by asset category, are as follows (dollars in thousands):

			Level 1						Level 2						Other (a)						Total
Pension Plan:
Fixed income securities:
Corporate			$	—					$	1,415,346					$	—					$	1,415,346
U.S. Treasury			622,273						—						—						622,273
Other (b)			—						135,184						—						135,184
Common stock equities (c)			150,657						—						—						150,657
Mutual funds (d)			112,791						—						—						112,791
Common and collective trusts:
Equities			—						—						192,945						192,945
Real estate			—						—						140,613						140,613
Other (e)			—						—						65,740						65,740
Total			$	885,721					$	1,550,530					$	399,298					$	2,835,549
Other Benefits:
Fixed income securities:
Corporate			$	—					$	189,902					$	—					$	189,902
U.S. Treasury			207,665						—						—						207,665
Other (b)			—						8,372						—						8,372
Common stock equities (c)			139,952						—						—						139,952
Mutual funds (d)			22,256						—						—						22,256
Common and collective trusts:
Equities			—						—						81,724						81,724
Real estate			—						—						20,001						20,001
Other (e)			21,146						—						5,476						26,622
Total			$	391,019					$	198,274					$	107,201					$	696,494

(a) These investments primarily represent assets valued using NAV as a practical expedient and have not been classified in the fair value hierarchy.

(b) This category consists primarily of debt securities issued by municipalities and asset backed securities.

(c) This category primarily consists of U.S. common stock equities.

(d) These funds invest in U.S. and international common stock equities.

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  In 2024 and 2023, we did not make any contributions to our pension plan. The expected minimum required cash contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2025, 2026 or 2027.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2024 or 2023 and do not expect to make any contributions in 2025, 2026 or 2027. The Company was reimbursed $ 27 million in 2024, $ 23 million in 2023, and $ 26 million in 2022 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

---

Estimated Future Benefit Payments

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):

Year						Pension Plans						Other Benefits Plans
2025						$	241,762					$	28,753
2026						223,562						28,747
2027						230,335						28,276
2028						233,617						27,880
2029						232,591						27,645
Years 2030-2034						1,147,273						137,301

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries.  In 2024, costs related to APS’s employees represented 99 % of the total cost of this plan.  In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments.  Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions.  Pinnacle West recorded expenses for this plan of approximately $ 14 million for 2024, $ 12 million for 2023, and $ 12 million for 2022.

We lease certain land, buildings, vehicles, equipment, and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power and energy storage agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2025 through 2073. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 17 for a discussion of VIEs.

APS has purchased power lease agreements that allow APS the right to the generation capacity from certain natural-gas fueled generators during certain months of each year throughout the term of the arrangements. As APS only has rights to use the assets during certain periods of each year, the leases have non-consecutive periods of use. APS does not operate or maintain the leased assets. APS controls the dispatch of the leased assets during the months of use and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets, APS has elected to combine both the

---

lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. In addition to the fixed monthly capacity payments, APS must also pay variable charges based on the actual production volume of the assets. The variable consideration is not included in the measurement of our lease obligation.

APS has executed various energy storage purchased power lease agreements that allow APS the right to charge and discharge energy storage facilities. APS pays a fixed monthly capacity price for rights to use the lease assets. The agreements generally have 20 -year lease terms and provide APS with the exclusive use of the energy storage assets through the lease term. APS does not operate or maintain the energy storage facilities and has no purchase options or residual value guarantees relating to these lease assets. For this class of energy storage lease assets, APS has elected to separate the lease and non-lease components. These leases are accounted for as operating leases, with lease terms that commenced between September 2023 and August 2024.

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

																		Year Ended December 31,
																														2024						2023						2022
Operating Lease Cost - Purchased Power & Energy Storage Lease Contracts																														$	147,313					$	126,655					$	104,001
Operating Lease Cost - Land, Property, and Other Equipment																														20,120						19,235						18,061
Total Operating Lease Cost																														167,433						145,890						122,062
Variable Lease Cost (a)																														144,108						135,007						122,040
Short-term Lease Cost																														20,653						21,530						9,928
Total Lease Cost																														$	332,194					$	302,427					$	254,030

(a)     Primarily relates to purchased power lease contracts.

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power and energy storage lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 3. The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements, we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheets.

---

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

						December 31, 2024
Year						Purchased Power & Energy Storage Lease Contracts						Land, Property & Equipment Leases						Total
2025						$	158,363					$	16,834					$	175,197
2026						172,087						14,830						186,917
2027						198,007						12,249						210,256
2028						201,804						9,591						211,395
2029						205,741						7,465						213,206
Thereafter						1,140,971						61,855						1,202,826
Total lease commitments						2,076,973						122,824						2,199,797
Less imputed interest						536,948						41,605						578,553
Total lease liabilities						$	1,540,025					$	81,219					$	1,621,244

We recognize lease assets and liabilities upon lease commencement. At December 31, 2024, 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 $ 16.7 billion over the terms of the agreements. These arrangements primarily relate to energy storage assets. We expect lease commencement dates ranging from March 2025 through June 2028, with lease terms expiring through June 2048. The lease commencement dates for certain arrangements have experienced delays. As a result of these delays and other events, APS has received cash proceeds from certain lessors prior to lease commencement. Proceeds received from lessors relating to energy storage PPA leases are accounted for as lease incentives on our Consolidated Balance Sheets, and upon lease commencement are amortized over the associated lease term. For regulatory purposes, the proceeds received by APS relating to these PPA leases are treated as a reduction to fuel and purchased power costs through the PSA in the period proceeds are received. See Note 3.

---

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

						Year Ended December 31,
						2024						2023						2022
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:						$	143,950					$	123,472					$	118,463
Right-of-use operating lease assets obtained in exchange for operating lease liabilities:						393,702			(a)			602,301			(b)			16,990

			December 31, 2024						December 31, 2023
Weighted average remaining lease term			11 years						10 years
Weighted average discount rate (c)			4.90		%				4.53		%

(a) Primarily relates to the three new energy storage operating lease agreements that commenced in 2024.

(b) Primarily relates to the two purchased power operating lease agreements that were modified in January 2023.

---

APS shares ownership of some of its generating and transmission facilities with other companies.  We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2024 (dollars in thousands):

						Percent Owned												Plant in Service						Accumulated Depreciation						Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3						29.1		%										$	2,010,346					$	1,081,321					$	20,694
Palo Verde Unit 2 (a)						16.8		%										709,414						397,235						9,076
Palo Verde Common						28.0		%				(b)						898,401						366,027						47,962
Palo Verde Sale Leaseback												(a)						351,050						268,494						—
Four Corners Generating Station						63.0		%										1,848,412						705,667						56,226
Cholla Common Facilities (c)						50.5		%										301,035						231,170						1,743
Transmission facilities:
Arizona Nuclear Power Project 500kV System						33.3		%				(b)						134,713						60,174						7,174
Navajo Southern System						24.7		%				(b)						88,528						38,797						626
Palo Verde — Yuma 500kV System						25.5		%				(b)						24,260						8,120						142
Four Corners Switchyards						58.0		%				(b)						84,367						23,886						309
Phoenix — Mead System						17.1		%				(b)						39,788						21,173						330
Palo Verde — Rudd 500kV System						50.0		%										95,785						34,254						1,808
Morgan — Pinnacle Peak System						63.2		%				(b)						117,500						29,013						287
Round Valley System						50.0		%										548						213						—
Palo Verde — Morgan System						87.5		%				(b)						266,547						46,327						208
Hassayampa — North Gila System						80.0		%										154,330						27,739						—
Cholla 500kV Switchyard						85.7		%										8,454						2,859						35
Saguaro 500kV Switchyard						60.0		%										29,850						15,768						101
Kyrene — Knox System						50.0		%										578						349						—
Agua Fria Switchyard						10.0		%										—						—						82

(a) See Note 17.

(b) Weighted-average of interests.

---

Palo Verde Generating Station

Spent Nuclear Fuel and Waste Disposal

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

APS has recovered costs for ten claims pursuant to the terms of the August 15, 2014 settlement agreement, for ten separate time periods during July 1, 2011, through October 31, 2023. The DOE has approved and paid approximately $ 156.7 million for these claims (APS’s share is approximately $ 45.6 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 3. On October 31, 2024, APS filed its eleven th claim pursuant to the terms of the August 15, 2014, settlement agreement in the amount of approximately $ 18 million (APS’s share is approximately $ 5.3 million). In February 2025, the DOE approved approximately $ 17.6 million of this claim.

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 $ 16.3 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $ 500 million, which is provided by American Nuclear Insurers.  The remaining balance of approximately $ 15.8 billion of liability coverage is provided through a mandatory, industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $ 165.9 million, subject to a maximum annual premium of approximately $ 24.7 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $ 144.9 million, with a maximum annual retrospective premium of approximately $ 21.6 million.

---

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $ 2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”).  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumul ated funds. Th e maximum amount APS could incur under the current NEIL policies totals approximately $ 23.1 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  Additionally, at the sole discretion of the NEIL Board of Directors, APS would be liable to provide approximately $ 64.1 million in deposit premium within 20 days of request as assurance to satisfy any site obligation of retrospective premium assessment.  The insurance coverage discussed in this, and the previous paragraph, is subject to certain policy conditions, sublimits, and exclusions.

Captive Insurance Cell

Pinnacle West has established a captive insurance program to supplement third-party insurance coverage for certain risks. The Captive insures Pinnacle West and its subsidiaries for terrorism coverage, excess liability including certain wildfire coverage, excess property insurance, and excess employment practice liability. These coverages may be supplemented with third-party insurance policies. The Captive policies exclude nuclear liability at Palo Verde. See Note 10. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments, which in the event of an insured loss would be available to pay covered claims. In the event of an insured loss event, Pinnacle West may be required to provide additional funding to the Captive. The Captive is a VIE, and Pinnacle West is the primary beneficiary of the VIE and consolidates the assets and liabilities of the Captive. See Note 17 for additional details.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2025 and 2048 that include required purchase provisions.  APS estimates the contract requirements to be approximately $ 1,540 million in 2025; $ 1,742 million in 2026; $ 1,973 million in 2027; $ 2,142 million in 2028; $ 2,115 million in 2029; and $ 27.2 billion thereafter.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts include estimated commitments relating to purchased power lease contracts. See Note 8.

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms expiring through 2031.

---

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):

			Year Ended December 31,
			2025						2026						2027						2028						2029						Thereafter (b)
Coal take-or-pay commitments (a)			$	208,984					$	214,090					$	212,529					$	217,820					$	223,291					$	463,752

(a) Total take-or-pay commitments are approximately $ 1.5 billion.  The total net present value of these commitments using a 4.81 % discount rate is approximately $ 1.3 billion.

(b) Through 2031.

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):

			Year Ended December 31,
			2024						2023						2022
Total purchases			$	237,821					$	255,219					$	305,502

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES.  APS estimates the contract requirements to be approximately $ 27 million in 2025; $ 24 million in 2026; $ 21 million in 2027; $ 18 million in 2028; $ 16 million in 2029; and $ 36 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.

Coal Mine Reclamation Obligations

Superfund and Other Related Matters

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to or disposed of hazardous substances at a

---

contaminated site are among the parties who are potentially responsible (each a “PRP”).  PRPs may be strictly, jointly, and severally liable for clean-up.  On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”).  The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. EPA notified APS that the RI/FS was approved on September 11, 2024. APS’s estimated costs related to this investigation and study is approximately $ 3 million. APS anticipates incurring additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

In connection with APS’s status as a PRP for OU3, since 2013 APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”). At this time, only one active lawsuit remains pending in the U.S. District Court for Arizona, which concerns $ 8.3 million in remediation legal expenses. APS is unable to predict the outcome of any further litigation related to this claim or APS’s share of liability related to that claim; however, APS does not expect the outcome to have a material impact on its financial position, results of operations or cash flows.

On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $ 1.7 million. At the present time, we are unable to predict the outcome of this matter, and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates but cannot predict whether it will obtain such recovery. The following proposed and final rules could involve material compliance costs to APS.

---

Coal Combustion Waste . On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

• Following the passage of the Water Infrastructure Improvements for the Nation (“WIIN”) Act in 2016, 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. At this time, Arizona Department of Environmental Quality (“ ADEQ”) has taken steps to develop a CCR permitting program and plans to propose state regulations governing CCR permitting over the summer of 2024. It remains unclear when EPA would approve that permitting program pursuant to the WIIN 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.

• 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.

• With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020. While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending. If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025. This application will be subject to public comment and, potentially, judicial review. We expect to have a proposed decision from EPA regarding Cholla in 2025.

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 CCR management units (“CCRMUs”), which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land. As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use (with exceptions for historical roadbed and embankment applications). Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs. At this time, APS is still evaluating the impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027. Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU asset retirement obligation. Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. The Navajo Plant disposed of CCR only in a dry landfill storage area. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units subject to alternative closure). APS completed the assessments of corrective measures on June 14, 2019; however, additional investigations and engineering analyses that will support the remedy selection are still underway. In addition, APS has also solicited input from the public and hosted public hearings as part of this process. APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, we cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate from the CCR rule’s corrective action assessment process for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.

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 the EPA on June 19, 2019 and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules. While the U.S. Court of Appeals for the D.C. Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for 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 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. Unlike EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, these new federal regulations are limited to measures that can be installed at individual power plants to limit planet-warming carbon-dioxide emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors. For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) by 2032. For intermediate or low-load natural gas fired combustion turbines, those with 40% or less capacity factors, EPA’s regulations would not require add-on pollution controls. Instead, natural gas-fired combustion turbines with capacity factors of up to 20% would be effectively unregulated, while such turbines with capacity factors over 20% and up to 40% would be subject to carbon dioxide emission rate limitations. EPA did not finalize standards for existing natural gas-fired combustion turbines but has indicated that it will propose a new set of standards, initiating a separate rulemaking, for these existing gas-fired power plants within the next year.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has finalized subcategories based on planned retirement dates. This means that facilities retiring before 2032 are effectively exempt from regulation, those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030, and those that retire in 2039 or later must install CCS controls by 2032.

As of May 10, 2024, several states, electric utility companies, affiliated trade associations, and other entities filed petitions for review of these regulations in the D.C. Circuit Court of Appeals. APS is participating in that litigation as part of an ad hoc coalition of electric utility companies, independent power producers, and trade groups, called Electric Generators for a Sensible Transition. We cannot predict the outcome of the litigation challenging EPA’s latest carbon emission standards for power plants. In addition, the Trump administration has stated that it intends to reverse or substantially revise these standards. We cannot predict the outcome of future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.

If this regulation remains in effect, it will likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants. The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install carbon capture and sequestration and achieve 90% capture efficiency may not be feasible. Future resource plans and procurement efforts implicating the development of such new generation remains pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s GHG regulations for power plants.

Effluent Limitation Guidelines. EPA published effluent limitation guidelines (“ELG”) on October 13, 2020, and, based off those guidelines, APS completed a National Pollutant Discharge Elimination System (“NPDES”) permit modification for Four Corners on December 1, 2023. The ELG standards finalized in October 2020 relaxed the “zero discharge” standard for bottom ash transport waters 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. Nonetheless, for power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards. APS is currently evaluating its

---

compliance options for Four Corners based on the ELG regulations finalized in April 2024 and is assessing what impacts the new standards will have on our financial condition, results of operations, or cash flows.

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 National Ambient Air Quality Standards (“NAAQS”). Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide (“NOx”) emissions. While Arizona was not among the 23 states subject to 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. As such, while EPA may elect to resume work on and finalize this proposal in the future, it is unlikely to do so over a near-term horizon. APS cannot predict the outcome of any future EPA efforts to add Arizona to the federal Good Neighbor Plan (which depends on action disapproving the Arizona State Implementation Plan) or whether the Good Neighbor Plan itself will remain in effect pending the outcome of judicial review in the D.C. Circuit Court of Appeals. Should the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load. At this time, APS cannot predict the impact on the Company’s financial condition, results of operations, or cash flows.

Revised Mercury and Air Toxics Standard (“MATS”) Proposal. On April 25, 2024, EPA finalized revisions to the existing MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants. The final regulations increase the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and require the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing). These final regulations will take effect for existing coal-fired power plants, such as Four Corners, within three years of publication in the Federal Register. Based on APS’s assessment of the revised MATS regulations, this final rule is unlikely to have a material impact on plant operations or require significant capital expenditures to ensure compliance.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.

---

APS would seek recovery in rates for the book value of any remaining investments in the plants, as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019, filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit. The EAB denied the environmental group petition on September 30, 2020. While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022. This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January 2021, and APS does not expect the outcome to have a material impact on its financial condition, results of operations, or cash flows.

BCE Kūpono Solar

BCE and Ameresco jointly owned a special purpose entity that sponsored the Kūpono Solar Project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that supplies energy and capacity under a 20 -year power purchase agreement with Hawaiian Electric Company, Inc. The Kūpono Solar Project achieved commercial operations in June 2024. On April 18, 2023, the Kūpono special purpose entity entered into a $ 140 million non-recourse construction financing agreement. On August 14, 2024, the construction financing converted into long-term financing in the form of a sale-leaseback. In connection with the project financing, Pinnacle West issued performance guarantees relating to the Kūpono Solar Project. Investments in the Kūpono Solar Project were included in the BCE Sale which closed on January 12, 2024, and as a result of the BCE Sale, Pinnacle West holds no equity or ownership interest in the Kūpono Solar Project. As of December 31, 2024, Pinnacle West continues to maintain performance guarantees relating to the Kūpono Solar Project sale-leaseback financing (see additional information below regarding these guarantees). See Note 20 for information relating to the BCE Sale.

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 December 31, 2024, standby letters of credit totaled approximately $ 18 million and surety bonds totaled approximately $ 23 million; both will expire through 2025. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be

---

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 at December 31, 2024. In connection with the sale of 4C Acquisition, LLC’s 7 % interest to Navajo Transitional Energy Corporation (“NTEC”), Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with PNW Power’s investments in minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farm in Minnesota, Pinnacle West has guaranteed the obligations of PNW Power to make production tax credit 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 December 31, 2024, there is approximately $ 29 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2031.

Pinnacle West has issued various performance guarantees in connection with the Kūpono Solar Project investment financing and is exposed to losses relating to these guarantees upon the occurrence of certain events that we consider to be remote. Subsequent to the BCE Sale, Pinnacle West continues to maintain these guarantees. See Note 20. 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. The details of the guarantees are as follows:

• Pinnacle West committed to certain performance guarantees tied to the Kūpono Solar Project achieving certain construction and operation milestones. These performance guarantees expired in August 2024. Pinnacle West has no on-going exposure under these construction-related guarantees.

In 2024 , the Company revised its cost estimates for existing AROs 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 $ 63 million, primarily due to cost estimates associated with the CCR Rule.

• Four Corners coal-fired power plant, which resulted in an increase of approximately $ 82 million, primarily due to cost estimates associated with the CCR Rule.

---

• Navajo, a decommissioned coal-fired power plant, which resulted in an increase of approximately $ 8 million.

• Palo Verde nuclear plant, which resulted in an increase of approximately $ 1 million.

• Solar, which resulted in a decrease to the ARO of approximately $ 11 million, primarily due to the reduced cost of solar panel disposal.

APS has also recorded the initial investigation and assessment costs related to the newly signed EPA rule for Legacy Impoundments and CCRMUs. At this time, APS is still estimating the financial impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027. Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU asset retirement obligation. Depending on the outcome of those evaluations and site investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

In 2023 , the Company revised its cost estimates for existing ARO 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 $ 71 million, primarily due to changes in the planned pond closure methodology and increased corrective action cost estimates associated with the CCR Rule.

• Four Corners coal-fired power plant, which resulted in a decrease of approximately $ 7 million.

• Navajo coal-fired plant, a decommissioned coal-fired power plant, which resulted in an increase of approximately $ 8 million.

• Palo Verde received a new decommissioning study, which resulted in an increase to the ARO in the amount of $ 63 million, an increase in the plant in service of $ 59 million and a decrease in the regulatory liability of $ 4 million.

See additional details in Notes 3 and 10 .

The following table shows the change in our asset retirement obligations (dollars in thousands):

						2024						2023
Asset retirement obligations at the beginning of year						$	966,001					$	797,762
Changes attributable to:
Accretion expense						56,143						44,269
Settlements						( 18,379 )						( 14,039 )
Estimated cash flow revisions						142,821						135,323
Newly incurred obligation						—						2,686
Asset retirement obligations at the end of year						$	1,146,586					$	966,001

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 3 for detail of regulatory liabilities.

---

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 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 18 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.

---

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 semi-monthly 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 at December 31, 2024, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

			Level 1						Level 2						Level 3						Other												Total
ASSETS
Cash equivalents			$	23					$	—					$	—					$	—											$	23
Risk management activities — derivative instruments:
Commodity contracts			—						13,152						7,176						( 3,770 )						(a)						16,558
Nuclear decommissioning trusts:
Equity securities			11,859						542						—						3,335						(b)						15,736
U.S. commingled equity funds			—						—						—						423,069						(c)						423,069
U.S. Treasury debt			367,396						—						—						—												367,396
Corporate debt			—						203,180						—						—												203,180
Mortgage-backed securities			—						208,533						—						—												208,533
Municipal bonds			—						37,429						—						—												37,429
Other fixed income			—						27,502						—						—												27,502
Subtotal nuclear decommissioning trusts			379,255						477,186						—						426,404												1,282,845
Other special use funds:
Cash equivalents			25,000						—						—						—						(d)						$	25,000
Equity securities			24,962						—						—						2,851						(b,d)						27,813
U.S. Treasury debt			355,544						—						—						—												355,544
Subtotal other special use funds (d)			405,506						—						—						2,851												408,357
Total assets			$	784,784					$	490,338					$	7,176					$	425,485											$	1,707,783
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts			$	—					$	( 40,388 )					$	( 22,215 )					$	817					(a)						$	( 61,786 )

(a) Represents counterparty netting, margin, and collateral. See Note 15.

(b) Represents net pending securities sales and purchases.

(c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

(d) All amounts relate to APS, with the exception of $ 34.2 million related to Pinnacle West’s Captive investments that are classified within Level 1, $ 25.0 million in cash equivalents and $ 9.2 million related to equity securities. See Note 17.

---

The following table presents the fair value at December 31, 2023, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

			Level 1						Level 2						Level 3						Other												Total
ASSETS
Cash equivalents			$	10					$	—					$	—					$	—											$	10
Risk management activities — derivative instruments:
Commodity contracts			—						1,881						6,616						( 1,689 )						(a)						6,808
Nuclear decommissioning trusts:
Equity securities			11,064						—						—						( 767 )						(b)						10,297
U.S. commingled equity funds			—						—						—						409,616						(c)						409,616
U.S. Treasury debt			319,734						—						—						—												319,734
Corporate debt			—						188,317						—						—												188,317
Mortgage-backed securities			—						208,306						—						—												208,306
Municipal bonds			—						59,323						—						—												59,323
Other fixed income			—						5,653						—						—												5,653
Subtotal nuclear decommissioning trusts			330,798						461,599						—						408,849												1,201,246
Other special use funds:
Equity securities			40,991						—						—						2,196						(b)						43,187
U.S. Treasury debt			319,594						—						—						—												319,594
Subtotal other special use funds			360,585						—						—						2,196												362,781
Total assets			$	691,393					$	463,480					$	6,616					$	409,356											$	1,570,845
LIABILITIES
Risk management activities — derivative instruments:
Commodity contracts			$	—					$	( 127,016 )					$	( 1,695 )					$	4,823					(a)						$	( 123,888 )

(a) Represents counterparty netting, margin, and collateral. See Note 15.

(b) Represents net pending securities sales and purchases.

(c) Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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. See Note 3.

---

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 at December 31, 2024, and December 31, 2023:

			December 31, 2024 Fair Value (thousands)												Valuation						Significant																		Weighted-Average
Commodity Contracts			Assets						Liabilities						Technique						Unobservable Input						Range												(b)
Electricity Forward Contracts (a)			$	708					$	21,890					Discounted cash flows						Electricity forward price (per MWh)						$ 25.25			-			$ 151.11						$ 106.06
Natural Gas Forward Contracts (a)			6,468						325						Discounted cash flows						Natural gas forward price (per MMBtu)						$( 0.89 )			-			$ 1.47						$ 0.71
Total			$	7,176					$	22,215

(a) Includes swaps and physical and financial contracts.

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

			December 31, 2023 Fair Value (thousands)												Valuation						Significant																		Weighted-Average
Commodity Contracts			Assets						Liabilities						Technique						Unobservable Input						Range												(b)
Electricity Forward Contracts (a)			$	6,587					$	658					Discounted cash flows						Electricity forward price (per MWh)						$	37.79		-			$ 259.04						$ 158.08
Natural Gas Forward Contracts (a)			29						1,037						Discounted cash flows						Natural gas forward price (per MMBtu)						$ 0.00			-			$ 0.08						$ 0.03
Total			$	6,616					$	1,695

(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):

												Year Ended December 31,
Commodity Contracts																		2024						2023
Balance at beginning of period																		$	4,921					$	( 4,888 )
Total net losses realized/unrealized:
Deferred as a regulatory asset or liability																		( 60,965 )						( 70,214 )
Settlements																		44,156						69,706
Transfers into Level 3 from Level 2																		( 4,635 )						( 1,289 )
Transfers from Level 3 into Level 2																		1,484						11,606
Balance at end of period																		$	( 15,039 )					$	4,921
Net unrealized gains/losses included in earnings related to instruments still held at end of period																		$	—					$	—

Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

ATM Program

On November 8, 2024, Pinnacle West entered into an equity distribution sales agreement, pursuant to which Pinnacle West may sell, from time to time, up to $ 900 million of its common stock through an ATM program, which includes the ability to enter into forward sale agreements. As of December 31, 2024 , approximately $ 850 million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreement in effect as of December 31, 2024 .

As of December 31, 2024 , Pinnacle West had an outstanding forward sale agreement under the ATM program relating to approximately $ 50 million of common stock (the “November 2024 ATM Forward Sale Agreement”). The November 2024 ATM Forward Sale Agreement may be settled at Pinnacle West’s discretion no later than June 30, 2026. On a given settlement date, Pinnacle West will issue shares of common at the then-applicable forward sales price. The terms of the November 2024 ATM Forward Sale Agreement also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The initial forward sales price for the November 2024 ATM Forward Sale Agreement was approximately $ 89.73 , subject to certain adjustments. On December 31, 2024 , Pinnacle West could have settled the outstanding November 2024 ATM Forward Sale Agreement with the physical delivery of 552,833 shares of Pinnacle West common stock in exchange for cash of approximately $ 50 million . As of December 31, 2024 , Pinnacle West has not received any proceeds relating to the November 2024 Forward

---

Sale Agreement. Pinnacle West will receive proceeds, if any, when settlement occurs, and will record the proceeds, if any, in equity.

Non-ATM February 2024 Forward Sale Agreements

On February 28, 2024, Pinnacle West executed equity forward sale agreements, relating to 11,240,601 shares of Pinnacle West common stock (“February 2024 Forward Sale Agreements”). The February 2024 Forward Sale Agreements may be settled at our discretion no later than September 4, 2025, and were not issued under the ATM program discussed above. On a settlement date, Pinnacle West will issue shares of Pinnacle West common stock and receive cash, if any, at the then-applicable forward sales price. The terms of the February 2024 Forward Sale Agreements also allow Pinnacle West, at its option, to settle the agreements with the counterparties by delivering cash, in lieu of shares.

The initial forward sales price for the February 2024 Forward Sale Agreements was initially, approximately $ 64.51 per share and is subject to adjustment based on the terms of the agreements. In December 2024, Pinnacle West partially settled the February 2024 Forward Sale Agreements with the issuance of 5,377,115 shares of common stock and received net proceeds of $ 345 million. The proceeds were recorded in equity.

At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock in exchange for cash of $ 377 million. We will not receive any additional proceeds, if any, from the February 2024 Forward Sale Agreements until settlement occurs.

Convertible Notes

In June 2024, Pinnacle West issued $ 525 million of 4.75 % convertible senior notes that will mature on June 15, 2027. The Convertible Notes conversion options are indexed to Pinnacle West’s common stock. See Note 5 .

---

Earnings Per Share

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

																														2024						2023						2022
Net income attributable to common shareholders																														$	608,806					$	501,557					$	483,602
Weighted average common shares outstanding — basic																														113,846						113,442						113,196
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units																														480						362						220
Dilutive shares related to equity forward sale agreements (a)																														1,906						—						—
Total contingently issuable shares																														2,386						362						220
Weighted average common shares outstanding — diluted																														116,232						113,804						113,416
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic																														$	5.35					$	4.42					$	4.27
Net income attributable to common shareholders — diluted																														$	5.24					$	4.41					$	4.26

(a)    For the years ended December 31, 2024, 2023 and 2022, diluted weighted average common shares excludes 1,038,463 , 0 and 0 shares, respectively, relating to the Convertible Notes and the ATM equity forward. These potentially issuable shares were excluded from the calculation of diluted shares as their inclusion would have been antidilutive.

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key employees, and non-officer members of the Board of Directors. Awards granted under the 2021 Long-Term Incentive Plan, as amended (“2021 Plan”), may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2021 Plan authorizes up to 4.3 million common shares to be available for grant.  As of December 31, 2024, 2.9 million common shares were available for issuance under the 2021 Plan. During 2024, 2023 and 2022, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”). No new awards may be granted under the 2012 or 2007 Plans.

---

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $ 24 million in 2024, $ 17 million in 2023, and $ 16 million in 2022.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $ 6 million in 2024, $ 3 million in 2023, and $ 2 million in 2022.

As of December 31, 2024, there were approximately $ 38 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of two years.

The total fair value of shares vested was $ 24 million in 2024, $ 24 million in 2023, and $ 25 million in 2022.

The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years:

			Restricted Stock Units, Stock Grants, and Stock Units (a)																		Performance Shares (b)
			2024						2023						2022						2024						2023						2022
Units granted			261,808						192,295						174,791						225,516						202,562						208,736
Weighted-average grant date fair value			$	71.10					$	74.32					$	69.66					$	72.89					$	79.61					$	77.63

(a) The Units granted does not include awards that will be cash settled in 2024, 2023 or 2022. See below for additional information on restricted stock unit grants.

(b) Reflects the target payout level.

The following table shows the change of nonvested awards:

			Restricted Stock Units, Stock Grants, and Stock Units												Performance Shares
			Shares						Weighted-Average Grant Date Fair Value						Shares (b)						Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2023			374,367						$	73.29					347,283						$	77.29
Granted			261,808						71.10						225,516						72.89
Vested			( 155,345 )						74.54						( 165,194 )						76.55
Forfeited (c)			( 20,039 )						71.32						( 17,054 )						75.69
Nonvested at December 31, 2024			460,791			(a)			71.72						390,551						77.29
Vested Awards Outstanding at December 31, 2024			70,851												165,194

(a) Includes 11,750 of awards that will be cash settled.

(b) The performance shares are reflected at target payout level.

(c) We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $ 8 million, $ 6 million, and $ 3 million in 2024, 2023 and 2022, respectively. This includes cash used to settle restricted stock units of $ 2

---

million, $ 3 million, and $ 3 million in 2024, 2023 and 2022, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees and typically vest and settle in equal annual installments over a 4 -year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period.

Beginning in 2022, restricted stock unit awards are issued in stock. Awards include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date. If the award is forfeited the employee is not entitled to the accrued reinvested dividends on those shares. Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, awardees typically elected to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.  Awards included a dividend equivalent feature that accrued dividend rights from the date of grant until the applicable vesting date, plus interest compounded quarterly. If the award was forfeited, the employee was not entitled to the accrued dividends on those shares. Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. Beginning in 2023, payments for stock units are issued in stock and include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date. Prior to 2023, members of the Board of Directors who elected to defer could elect to receive payment in either 100 % stock, 100 % cash, or 50 % in cash and 50 % in stock.  The stock units prior to 2023 included a dividend equivalent feature that accrues dividend rights from the date of grant to the date of payment, plus interest compounded quarterly.

Performance Share Awards

Performance share awards are granted to officers and key employees.  The awards contain separate performance metric criteria that affect the number of shares that may be received if, after the end of a 3 -year performance period, the performance criteria are met.

Beginning in 2022, performance share awards contain three separate, unrelated performance criteria. The first performance criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The second performance criteria is based upon Pinnacle West’s earnings per share (“EPS”) performance relative to an

---

approved target (i.e., the EPS component). The third performance criteria is based upon APS’s clean MW installed of renewable or other carbon free resources compared to the approved target (i.e., the Clean component). The exact number of shares issued is calculated separately for each performance component and can vary from 0 % to 200 % of the target award for each separate performance criteria. Shares received include a dividend equivalent feature that treats accrued dividends as reinvested, from the date of grant until the date of payment, equal to the number of vested performance shares. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares. Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the employee’s retirement.

Prior to 2022, performance share awards had two performance criteria. The first performance criteria was based upon non-financial performance metrics (i.e., the Metric component). The second performance criteria was based upon Pinnacle West’s TSR in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0 % to 200 % of the target award. Shares received included a dividend equivalent feature that allows accrued dividend rights from the date of grant until the date of payment, plus interest compounded quarterly, equal to the number of vested performance shares. If the award was forfeited, the employee was not entitled to the accrued dividends on those shares. Awards granted to retirement-eligible employees typically vested upon the employee’s retirement.

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 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 balance sheets as an asset or liability and are measured at fair value.  See Note 12 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 Note 5 for Pinnacle West’s Convertible Notes. These equity-linked transactions are indexed to Pinnacle West common stock and qualify for a derivative scope exception, and as such, are not subject to mark-to-market accounting and are excluded from the derivative disclosures below.

Energy Derivatives

For its regulated operations, APS defers for future rate treatment 100 % of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate. See Note 3.  Gains and losses from energy derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

The following table shows the outstanding gross notional volume of energy derivatives, which represent both purchases and sales (does not reflect net position):

Quantity

Commodity

Unit of Measure

December 31, 2024

December 31, 2023

Power

GWh

1,051

1,212

Gas

Billion cubic feet

235

200

Gains and Losses from Energy Derivative Instruments

For the years ended December 31, 2024, 2023 and 2022, APS had no energy derivative instruments in designated accounting hedging relationships.

									Financial Statement																		Year Ended December 31,
Commodity Contracts									Location																														2024						2023						2022
Net Gain (Loss) Recognized in Income									Fuel and purchased power (a)																														( 88,522 )						( 370,145 )						307,287

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

---

Energy Derivative Instruments in the 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 Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the 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 Consolidated Balance Sheets.

As of December 31, 2024: (dollars in thousands)						Gross Recognized Derivatives (a)						Amounts Offset (b)						Net Recognized Derivatives						Other (c)						Amounts Reported on Balance Sheets
Current assets						$	13,718					$	( 3,158 )					$	10,560					$	18					$	10,578
Investments and other assets						6,610						( 630 )						5,980						—						5,980
Total assets						20,328						( 3,788 )						16,540						18						16,558
Current liabilities						( 52,527 )						3,158						( 49,369 )						( 2,971 )						( 52,340 )
Deferred credits and other						( 10,076 )						630						( 9,446 )						—						( 9,446 )
Total liabilities						( 62,603 )						3,788						( 58,815 )						( 2,971 )						( 61,786 )
Total						$	( 42,275 )					$	—					$	( 42,275 )					$	( 2,953 )					$	( 45,228 )

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

(b) No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c) Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $ 2,971 thousand and cash margin provided to counterparties of $ 18 thousand.

---

As of December 31, 2023: (dollars in thousands)						Gross Recognized Derivatives (a)						Amounts Offset (b)						Net Recognized Derivatives						Other (c)						Amounts Reported on Balance Sheets
Current assets						$	8,497					$	( 1,694 )					$	6,803					$	5					$	6,808
Investments and other assets						—						—						—						—						—
Total assets						8,497						( 1,694 )						6,803						5						6,808
Current liabilities						( 85,736 )						10,894						( 74,842 )						( 6,071 )						( 80,913 )
Deferred credits and other						( 42,975 )						—						( 42,975 )						—						( 42,975 )
Total liabilities						( 128,711 )						10,894						( 117,817 )						( 6,071 )						( 123,888 )
Total						$	( 120,214 )					$	9,200					$	( 111,014 )					$	( 6,066 )					$	( 117,080 )

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

(b) Includes cash collateral provided to counterparties of $ 9,200 thousand 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 $ 6,071 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 December 31, 2024, we have one counterparty for which our exposure represents approximately 26 % of Pinnacle West’s $ 16.6 million of risk management assets. This exposure relates to an ISDA master agreement with the respective counterparty. The counterparty is rated as investment grade by Standard & Poor’s. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties’ debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our energy derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those energy derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

---

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

			December 31, 2024
Aggregate fair value of derivative instruments in a net liability position			$	62,603
Additional collateral in the event credit-risk related contingent features were fully triggered (a)			32,728

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

We also have energy related non-derivative instrument contracts, including energy storage lease contracts, with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $ 416 million if our debt credit ratings were to fall below investment grade.

The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2024, 2023, and 2022 (dollars in thousands):

						2024						2023						2022
Other income:
Interest income						$	24,322		(a)			$	27,242		(a)			$	7,326
Gain on sale of BCE (Note 20)						22,988						6,205						—
Miscellaneous						1,304						219						590
Total other income						$	48,614					$	33,666					$	7,916
Other expense:
Non-operating costs						$	( 27,370 )		(b)			$	( 15,260 )					$	( 18,619 )
Investment losses — net						( 1,418 )						( 3,402 )						( 20,537 )			(c)
Miscellaneous						( 5,348 )						( 6,394 )						( 13,229 )
Total other expense						$	( 34,136 )					$	( 25,056 )					$	( 52,385 )

(a) The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 3.

(b) The 2024 Non-operating cost is primarily related to corporate giving.

(c) The 2022 investment loss is primarily related to an impairment of PNW Power’s Clear Creek wind farm investment.

---

						2024						2023						2022
Other income:
Interest income (a)						$	21,088		(a)			$	26,853		(a)			$	5,332
Miscellaneous						6						219						556
Total other income						$	21,094					$	27,072					$	5,888
Other expense:
Non-operating costs						$	( 26,588 )		(b)			$	( 14,070 )					$	( 15,579 )
Miscellaneous						( 3,110 )						( 4,194 )						( 10,529 )
Total other expense						$	( 29,698 )					$	( 18,264 )					$	( 26,108 )

(a) The 2023 and 2024 Interest income is primarily related to PSA Interest. See Note 3.

(b) The 2024 Non-operating cost is primarily related to corporate giving.

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 10 for details regarding nuclear liability insurance. Claim payments to the insureds can only be made up to the amount of the Captive’s available assets. In the event that claims exceed the Captive’s available assets, Pinnacle West may be required to provide additional funding to the Captive. In addition to policies obtained through the Captive, Pinnacle West also has insurance policies purchased through third-party insurers that may provide coverage if a loss event occurs.

As a result of consolidation, we eliminate intercompany transactions between Pinnacle West and the Captive and record the Captive’s assets, liabilities and third-party operating activities. In consolidation,

---

the Captive’s insurance premium revenues derived from Pinnacle West policies is 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 our Consolidated Balance Sheets, and the Captive’s investment gains and losses reflected through earnings on our Consolidated Income Statements.

Consolidation of the Captive resulted in an increase in Pinnacle West net income of $ 5 million for 2024, and zero for 2023 and 2022. These amounts are fully attributable to Pinnacle West shareholders. Consolidation impacts Pinnacle West Consolidated Income Statement’s operations and maintenance expense and other income line items.

Pinnacle West’s Consolidated Balance Sheets as of December 31, 2024 include $ 34 million of assets relating to the Captive that is reported within the other special use funds line item. See Notes 12 and 18 for additional details on these investment holdings. Our Consolidated Balance Sheets as of December 31, 2023, include $ 5 million of assets relating to the Captive that is reported within the other assets line item.

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. APS will retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to the three leases in total of approximately $ 21 million annually for the period 2025 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years , or return the assets to the lessors.

The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

---

Our Consolidated Balance Sheets include the following amounts relating to these VIEs (dollars in thousands):

			December 31, 2024						December 31, 2023
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation			$	82,556					$	86,426
Equity — Noncontrolling interests			103,167						107,198

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written-down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $ 345 million beginning in 2025, and up to $ 501 million over the lease extension terms.

For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

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 Consolidated Balance Sheets. See Note 12 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities.

Coal Reclamation Escrow Account — APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below.

---

Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2024 and 2023, APS was reimbursed $ 14 million for each year, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory assets and liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

Captive Insurance Cell — Pinnacle West has investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments. These investments are restricted for insured loss events.

Pinnacle West Consolidated investment holdings reflected in the tables below primarily relate to APS, with the exception of the Captive’s investments included within Other Special Use Funds.

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of the nuclear decommissioning trusts and other special use fund assets (dollars in thousands):

			December 31, 2024
			Fair Value																		Total Unrealized Gains						Total Unrealized Losses
Investment Type:			Nuclear Decommissioning Trusts						Other Special Use Funds						Total
Equity securities			$	435,470					$	24,962					$	460,432					$	359,127					$	( 176 )
Available for sale-fixed income securities			844,040						355,544						1,199,584			(a)			7,717						( 31,960 )
Other			3,335						27,851						31,186			(b)			—						—
Total			$	1,282,845					$	408,357					$	1,691,202		(c)			$	366,844					$	( 32,136 )

(a) As of December 31, 2024, the amortized cost basis of these available-for-sale investments is $ 1,224 million.

(b) Represents net pending securities sales and purchases.

(c) All amounts pertain to APS, with the exception of $ 34 million of Other Special Use Fund investments in equity securities relating to the Captive.

			December 31, 2023
			Fair Value																		Total Unrealized Gains						Total Unrealized Losses
Investment Type:			Nuclear Decommissioning Trusts						Other Special Use Funds						Total
Equity securities			$	420,680					$	40,991					$	461,671					$	336,555					$	—
Available for sale-fixed income securities			781,333						319,594						1,100,927			(a)			21,518						( 40,868 )
Other			( 767 )						2,196						1,429			(b)			39						—
Total			$	1,201,246					$	362,781					$	1,564,027		(c)			$	358,112					$	( 40,868 )

(a) As of December 31, 2023, the amortized cost basis of these available-for-sale investments is $ 1,120 million.

(b) Represents net pending securities sales and purchases.

(c) All amounts pertain to APS.

---

			Year Ended December 31,
			Nuclear Decommissioning Trusts						Other Special Use Funds						Total
2024
Realized gains			$	75,690					$	372					$	76,062
Realized losses			$	( 21,966 )					$	—					$	( 21,966 )
Proceeds from the sale of securities (a)			$	1,330,940					$	355,154					$	1,686,094
2023
Realized gains			$	111,922					$	172					$	112,094
Realized losses			$	( 41,212 )					$	( 568 )					$	( 41,780 )
Proceeds from the sale of securities (a)			$	1,324,978					$	354,744					$	1,679,722
2022
Realized gains			$	9,017					$	420					$	9,437
Realized losses			$	( 40,239 )					$	—					$	( 40,239 )
Proceeds from the sale of securities (a)			$	979,639					$	227,558					$	1,207,197

(a) Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.

Fixed Income Securities Contractual Maturities

The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31, 2024, is as follows (dollars in thousands):

			Nuclear Decommissioning Trusts						Coal Reclamation Escrow Account						Active Union Employee Medical Account						Total
Less than one year			$	19,868					$	87,424					$	39,090					$	146,382
1 year – 5 years			268,974						58,598						154,768						482,340
5 years – 10 years			198,464						—						15,664						214,128
Greater than 10 years			356,734						—						—						356,734
Total			$	844,040					$	146,022					$	209,522					$	1,199,584

---

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

			Pension and Other Postretirement Benefits												Derivative Instruments						Total
Balance at December 31, 2022			$	( 32,332 )											$	897					$	( 31,435 )
Other comprehensive income/(loss) before reclassifications			( 4,420 )												713						( 3,707 )
Amounts reclassified from accumulated other comprehensive loss			1,998						(a)						—						1,998
Balance at December 31, 2023			( 34,754 )												1,610						( 33,144 )
Other comprehensive income/(loss) before reclassifications			1,039												( 891 )						148
Amounts reclassified from accumulated other comprehensive loss			2,054						(a)						—						2,054
Balance at December 31, 2024			$	( 31,661 )											$	719					$	( 30,942 )

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.

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

			Pension and Other Postretirement Benefits
Balance at December 31, 2022			$	( 15,596 )
Other comprehensive (loss) before reclassifications			( 3,383 )
Amounts reclassified from accumulated other comprehensive loss			1,760						(a)
Balance at December 31, 2023			( 17,219 )
Other comprehensive income before reclassifications			1,255
Amounts reclassified from accumulated other comprehensive loss			1,848						(a)
Balance at December 31, 2024			$	( 14,116 )

(a) These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7.

---

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary, BCE, to Ameresco. The transaction is accounted for as the sale of a business and was structured to close in multiple stages that were completed on January 12, 2024. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a wholly-owned subsidiary of Pinnacle West. The BCE Sale did not include a $ 31 million equity bridge loan relating to BCE’s Los Alamitos project, which was paid in full by Pinnacle West on August 4, 2023. Other than these retained investments and the debt instrument, all BCE assets and liabilities were included in the BCE Sale and were transferred to Ameresco.

The total carrying value of net assets transferred to Ameresco as a result of the BCE Sale was $ 79 million, with total consideration received by Pinnacle West of $ 108 million, resulting in a total pre-tax gain of $ 29 million, which was recognized between August 4, 2023 and January 12, 2024. The net assets transferred includes $ 41 million of liabilities that have been assumed by Ameresco. The consideration received by Pinnacle West includes both cash and interest-bearing promissory notes. The stages of the BCE Sale and timing of net assets transferring to Ameresco and related gain recognition are as follows:

• The first stage of the BCE Sale was completed on August 4, 2023. In the first stage, the net assets transferred to Ameresco totaled $ 44 million, which included a $ 36 million construction term loan. The assets and liabilities transferred in the first stage related to the BCE Los Alamitos project and were previously primarily classified as construction work in progress and current maturities of long-term debt, respectively. A gain of $ 6 million was recognized on our Consolidated Statements of Income for the year ended December 31, 2023, relating to the first stage of the BCE Sale.

• The final stage of the BCE Sale was completed on January 12, 2024. In the final stage, the net assets transferred to Ameresco totaled $ 35 million. The assets transferred in the final stage related primarily to equity method investments in the Kūpono Solar Project and other development stage projects. These assets were previously classified as assets held for sale on our December 31, 2023, Consolidated Balance Sheets. Our Consolidated Statements of Income for the year ended December 31, 2024, include a $ 23 million gain relating to the final stage of the BCE Sale.

As of January 12, 2024, all stages of the BCE Sale have been completed. As partial consideration for the BCE Sale, Pinnacle West received a $ 46 million interest-bearing promissory note from Ameresco. The note required Ameresco to make cash payments to Pinnacle West throughout 2024 and Pinnacle West received payment in full of the note receivable during the fourth quarter of 2024. As the note receivable has been paid in full, our December 31, 2024 Consolidated Balance Sheets do not include any amounts relating to the promissory note.

On January 30, 2024, Pinnacle West entered into a tax credit transfer agreement to purchase from Ameresco $ 23 million of investment tax credits from the BCE Los Alamitos project for $ 21 million. See Note 4.

---

ASU 2023-07, Segment Reporting: Improvements to Reportable Segment Disclosures

In November 2023, a new standard was issued that modifies segment reporting disclosure requirements. The disclosure changes include information about a reportable segment’s significant expenses, details relating to the entity’s chief operating decision maker, and other disclosures. We adopted this standard on December 31, 2024, using a retrospective approach. The adoption of the new standard results in changes to our reportable segment disclosures, but does not impact how we identify reportable segments or our financial statement results. See Note 1.

ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures

In December 2023, a new accounting standard was issued that expands disclosures relating to income taxes. The expanded disclosures include a tabular income tax rate reconciliation, disclosure of specific reconciliation categories and reconciling items, the amount of income taxes paid by jurisdiction, and other disclosures. We will adopt this standard on December 31, 2025, using a prospective approach. The adoption of the new standard will result in changes to our income tax disclosures, but will not impact our accounting for income taxes or our financial statement results.

ASU 2024-03, Income Statement: Expense Disaggregation Disclosures

In November 2024, a new accounting standard was issued that requires specific disclosures related to certain costs and expenses. Companies will be required to disclose the amounts of certain cost and expense categories, such as: purchases of inventory, employee compensation, depreciation, and 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 income statement. The standard is effective for us 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.

---

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

			Year Ended December 31,
			2024						2023						2022
Operating expenses			$	9,931					$	11,249					$	8,850
Other
Equity in earnings of subsidiaries			643,703						539,962						500,042
Other income (expense)			23,835						2,823						( 4,725 )
Total			667,538						542,785						495,317
Interest expense			65,261						47,251						18,861
Income before income taxes			592,346						484,285						467,606
Income tax benefit			( 16,460 )						( 17,272 )						( 15,996 )
Net income attributable to common shareholders			608,806						501,557						483,602
Other comprehensive income (loss) — attributable to common shareholders			2,202						( 1,709 )						23,426
Total comprehensive income — attributable to common shareholders			$	611,008					$	499,848					$	507,028

See Combined Notes to Consolidated Financial Statements.

---

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)

			December 31,
			2024						2023
ASSETS
Current assets
Cash and cash equivalents			$	23					$	9
Accounts receivable			163,203						163,829
Income tax receivable			6,673						1,832
Assets held for sale- investment in subsidiaries			—						35,139
Other current assets			434						28,379
Total current assets			170,333						229,188
Investments and other assets
Investments in subsidiaries			8,435,150						7,369,159
Deferred income taxes			—						15,746
Other assets			21,966						22,839
Total investments and other assets			8,457,116						7,407,744
TOTAL ASSETS			$	8,627,449					$	7,636,932
LIABILITIES AND EQUITY
Current liabilities
Accounts payable			$	3,471					$	8,176
Accrued taxes			4,799						4,543
Common dividends payable			106,592						99,813
Short-term borrowings			228,550						76,650
Current maturities of long-term debt			500,000						625,000
Operating lease liabilities			138						127
Other current liabilities			11,389						11,400
Total current liabilities			854,939						825,709
Long-term debt less current maturities			867,770						498,731
Deferred income taxes			24,536						—
Pension liabilities			4,462						6,487
Operating lease liabilities			1,194						1,332
Other			17,070						19,811
Total deferred credits and other			47,262						27,630
COMMITMENTS AND CONTINGENCIES
Common stock equity
Common stock			3,118,294						2,744,491
Accumulated other comprehensive loss			( 30,942 )						( 33,144 )
Retained earnings			3,666,959						3,466,317
Total Pinnacle West Shareholders’ equity			6,754,311						6,177,664
Noncontrolling interests			103,167						107,198
Total Equity			6,857,478						6,284,862
TOTAL LIABILITIES AND EQUITY			$	8,627,449					$	7,636,932

See Combined Notes to Consolidated Financial Statements.

---

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)

			Year Ended December 31,
			2024						2023						2022
Cash flows from operating activities
Net income			$	608,806					$	501,557					$	483,602
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net			( 643,703 )						( 539,962 )						( 500,042 )
Gain on sale relating to BCE			( 22,988 )						( 6,423 )						—
Depreciation and amortization			75						76						76
Deferred income taxes			40,231						( 13,955 )						17,256
Accounts receivable			15,268						( 28,273 )						( 8,535 )
Accounts payable			( 4,869 )						1,839						3,431
Accrued taxes and income tax receivables — net			( 4,584 )						9,505						( 25,157 )
Dividends received from subsidiaries			401,400						393,600						385,800
Other			22,959						( 14,201 )						47,719
Net cash flow provided by operating activities			412,595						303,763						404,150
Cash flows from investing activities
Proceeds from sale relating to BCE			84,322						23,400						—
Investments in subsidiaries			( 827,752 )						( 119,682 )						( 186,630 )
Repayments of loans from subsidiaries and other			1,132						6,526						14,308
Advances of loans to subsidiaries			( 11,336 )						( 59,349 )						( 3,308 )
Net cash flow used for investing activities			( 753,634 )						( 149,105 )						( 175,630 )
Cash flows from financing activities
Issuance of long-term debt			867,387						175,000						300,000
Short-term debt borrowings under revolving credit facility			200,000						—						—
Short-term borrowings and (repayments) — net			( 48,100 )						60,930						2,420
Dividends paid on common stock			( 394,663 )						( 386,486 )						( 378,881 )
Repayment of long-term debt			( 625,000 )						—						( 150,000 )
Common stock equity issuance and purchases — net			341,429						( 4,093 )						( 2,653 )
Net cash flow used for financing activities			341,053						( 154,649 )						( 229,114 )
Net increase (decrease) in cash and cash equivalents			14						9						( 594 )
Cash and cash equivalents at beginning of year			9						—						594
Cash and cash equivalents at end of year			$	23					$	9					$	—

See Combined Notes to Consolidated Financial Statements.

---

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---