Commitments and Contingencies	3 Months Ended
Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Palo Verde Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the U.S. Department of Energy (“DOE”) in the U.S. Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007, through June 30, 2011, pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025. APS has submitted nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022. The DOE has approved and paid $138.2 million for these claims (APS’s share is $40.2 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 4. On October 31, 2023, APS filed its tenth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $18.46 million (APS’s share is $5.4 million). On March 21, 2024, the DOE approved a payment in the amount of $18.39 million (APS’s share is $5.4 million), and payment is anticipated in the second quarter of 2024. 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 accumulated funds. The 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. Fuel and Purchased Power Commitments and Purchase Obligations As of March 31, 2024, our fuel and purchased power and purchase obligation commitments have increased by $295 million from the information provided in our 2023 Form 10-K. The change is primarily due to new purchased power commitments. The majority of the changes relate to 2026 and thereafter. At March 31, 2024, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2024 through June 2025, with terms expiring through May 2045. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $7.1 billion over the term of the arrangements. The lease commencement dates for these leased assets have experienced delays. APS continues to work with the lessors to determine the revised commencement dates that will be achieved. For additional information regarding our lease commitments, see our 2023 Form 10-K. Other than the items described above, there have been no material changes, as of March 31, 2024, outside the normal course of business in contractual obligations from the information provided in our 2023 Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations. Superfund and Other Related Matters The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a 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. APS cannot predict the EPA’s timing with respect to this matter. 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 ultimate remediation requirements are not yet finalized by EPA, 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, which is on appeal to the U.S. Court of Appeals for the Ninth Circuit based on a U.S. District Court order dismissing cost recovery claims of approximately $20.7 million by a service provider for RID. 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 our 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 the Company 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 coal combustion residuals (“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 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. Although the Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. 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 sometime in 2024. We cannot at this time 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 within 21 months following publication of this final regulation in the Federal Register. Depending on the outcome of that evaluation, 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 by April 11, 2021, at the latest (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 will also solicit input from the public and host 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, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate 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. At this time, APS continues to assess the recently finalized EPA carbon emission standards and cannot yet predict their potential impact on APS’s operations. The costs associated with APS’s operation of its current thermal plants and construction and operation of future facilities could materially increase, which could affect our financial condition, results of operations, or cash flows. 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 of 2020 relaxed the “zero discharge” standard for bottom ash transport waters EPA finalized in September of 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. Since 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. APS cannot predict the outcome of EPA’s proposal or the extent to which such regulations, if finalized, could materially impact our 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. APS continues to evaluate this new regulation and its impact on Four Corners. Depending on the outcome of that assessment, the costs associated with APS’s controls for filterable particulate matter could materially increase, which could affect APS’s financial position, results of operations, or cash flows. 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 of 2021, and APS does not expect the outcome to have a material impact on our financial condition, results of operations, or cash flows. BCE Kūpono Solar BCE and Ameresco jointly owned a special purpose entity that is sponsoring the Kūpono Solar Project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year power purchase agreement with Hawaiian Electric Company, Inc. The Kūpono Solar Project is expected to be completed in 2024. On April 18, 2023, the Kūpono solar special purpose entity entered into a $140 million non-recourse construction financing agreement. The construction financing will convert into a sale leaseback agreement upon commercial operation of the project. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project. Investments in the Kūpono Solar Project are included in the BCE Sale which closed on January 12, 2024. As a result of the BCE Sale, on March 31, 2024, Pinnacle West holds no equity or ownership interest in the Kūpono Solar Project. Subsequent to the BCE Sale, Pinnacle West continues to maintain the performance guarantees relating to the Kūpono Solar Project financing (see additional information below regarding these guarantees). See Note 14 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 March 31, 2024, standby letters of credit totaled approximately $35 million and surety bonds totaled approximately $21 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 March 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 March 31, 2024, there is approximately $31 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2030. 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 do not consider to be reasonably likely to occur. Subsequent to the BCE Sale, Pinnacle West continues to maintain these performance guarantees. See Note 14. Pinnacle West has not needed to perform under these guarantees. Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated. We consider the fair value of these guarantees, including expected credit losses, to be immaterial. The details of the guarantees are as follows: •Upon the BCE Sale closing, on January 12, 2024, Pinnacle West committed to certain performance guarantees tied to the Kūpono project achieving certain construction and operation milestones. These performance guarantees will expire when the Kūpono project achieves commercial operation, which is expected in May 2024. If the Kūpono project is unable to achieve commercial operation, Pinnacle West may incur losses relating to these guarantees. The guarantees provide support relating to the $140 million Kūpono construction financing agreements, described above. As of March 31, 2024, we cannot reasonably estimate the range of loss that may occur; however, the likelihood of any payment under these guarantees is considered remote. •When the Kūpono financing converts to a sale leaseback agreement, which is expected to occur upon commercial operation of the project, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events (such as uninsured loss events). Ameresco has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030. •Ameresco is obligated to reimburse Pinnacle West for any payments made by Pinnacle West under such guarantees.

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

APS has submitted nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022. The DOE has approved and paid $138.2 million for these claims (APS’s share is $40.2 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 4. On October 31, 2023, APS filed its tenth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $18.46 million (APS’s share is $5.4 million). On March 21, 2024, the DOE approved a payment in the amount of $18.39 million (APS’s share is $5.4 million), and payment is anticipated in the second quarter of 2024.

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 accumulated funds. The 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.

At March 31, 2024, we have various lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to energy storage assets, with expected lease commencement dates ranging from June 2024 through June 2025, with terms expiring through May 2045. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $7.1 billion over the term of the arrangements. The lease commencement dates for these leased assets have experienced delays. APS continues to work with the lessors to determine the revised commencement dates that will be achieved. For additional information regarding our lease commitments, see our 2023 Form 10-K.

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. APS cannot predict the EPA’s timing with respect to this matter. 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 ultimate remediation requirements are not yet finalized by EPA, 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, which is on appeal to the U.S. Court of Appeals for the Ninth Circuit based on a U.S. District Court order dismissing cost recovery claims of approximately $20.7 million by a service provider for RID. 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 our 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 the Company 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.

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 coal combustion residuals (“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 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. Although the Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. 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 sometime in 2024.

We cannot at this time 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 within 21 months following publication of this final regulation in the Federal Register. Depending on the outcome of that evaluation, 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 by April 11, 2021, at the latest (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 will also solicit input from the public and host 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, APS cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate 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

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.

At this time, APS continues to assess the recently finalized EPA carbon emission standards and cannot yet predict their potential impact on APS’s operations. The costs associated with APS’s operation of its current thermal plants and construction and operation of future facilities could materially increase, which could affect our financial condition, results of operations, or cash flows.

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 of 2020 relaxed the “zero discharge” standard for bottom ash transport waters EPA finalized in September of 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. Since 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. APS cannot predict the outcome of EPA’s proposal or the extent to which such regulations, if finalized, could materially impact our 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. APS continues to evaluate this new regulation and its impact on Four Corners. Depending on the outcome of that assessment, the costs associated with APS’s controls for filterable particulate matter could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

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.

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 of 2021, and APS does not expect the outcome to have a material impact on our financial condition, results of operations, or cash flows.

BCE and Ameresco jointly owned a special purpose entity that is sponsoring the Kūpono Solar Project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year power purchase agreement with Hawaiian Electric Company, Inc. The Kūpono Solar Project is expected to be completed in 2024. On April 18, 2023, the Kūpono solar special purpose entity entered into a $140 million non-recourse construction financing agreement. The construction financing will convert into a sale leaseback agreement upon commercial operation of the project. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project. Investments in the Kūpono Solar Project are included in the BCE Sale which closed on January 12, 2024. As a result of the BCE Sale, on March 31, 2024, Pinnacle West holds no equity or ownership interest in the Kūpono Solar Project. Subsequent to the BCE Sale, Pinnacle West continues to maintain the performance guarantees relating to the Kūpono Solar Project financing (see additional information below regarding these guarantees). See Note 14 for information relating to the BCE Sale.

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of March 31, 2024, standby letters of credit totaled approximately $35 million and surety bonds totaled approximately $21 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.

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 March 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 March 31, 2024, there is approximately $31 million of remaining guarantees relating to these PTC Guarantees that are expected to terminate by 2030.

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 do not consider to be reasonably likely to occur. Subsequent to the BCE Sale, Pinnacle West continues to maintain these performance guarantees. See Note 14. Pinnacle West has not needed to perform under these guarantees. Maximum obligations are not explicitly stated in the guarantees and cannot be reasonably estimated. We consider the fair value of these guarantees, including expected credit losses, to be immaterial. The details of the guarantees are as follows:

•Upon the BCE Sale closing, on January 12, 2024, Pinnacle West committed to certain performance guarantees tied to the Kūpono project achieving certain construction and operation milestones. These performance guarantees will expire when the Kūpono project achieves commercial operation, which is expected in May 2024. If the Kūpono project is unable to achieve commercial operation, Pinnacle West may incur losses relating to these guarantees. The guarantees provide support relating to the $140 million Kūpono construction financing agreements, described above. As of March 31, 2024, we cannot reasonably estimate the range of loss that may occur; however, the likelihood of any payment under these guarantees is considered remote.

•When the Kūpono financing converts to a sale leaseback agreement, which is expected to occur upon commercial operation of the project, Pinnacle West has committed to certain performance guarantees that may apply upon the occurrence of specified events (such as uninsured loss events). Ameresco has agreed to make efforts to refinance the project and eliminate these guarantees prior to 2030.