INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes to the Condensed Consolidated Financial Statements (“Notes”) that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part 1, Item 1A of the 2025 Form 10-K and Part II, Item 1A of this report.
OVERVIEW
Business Overview
Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $33 billion. We derive essentially all of our revenues and earnings from our principal subsidiary, APS. Since 1886, APS and its affiliates have provided energy and energy-related products to people and businesses throughout Arizona. APS is Arizona’s largest and longest-serving electric company and generates safe, affordable and reliable electricity for approximately 1.5 million retail customers in 11 of Arizona’s 15 counties. APS is also the operator and co-owner of Palo Verde — a primary source of electricity for the southwestern United States. Our other active subsidiaries are El Dorado and PNW Power.
Strategic Overview
Our vision is to create a sustainable energy future for Arizona. Our mission is to serve customers with safe, reliable, and affordable energy. We are committed to delivering operational excellence at the lowest cost possible while aspiring to lower carbon emissions over time.
Reliable
As energy demand in Arizona continues to grow, we remain committed to delivering reliable service to our customers. We have a goal of achieving top quartile reliability as compared to peers. Key elements to delivering reliable service include resource and transmission planning to maintain resource adequacy, distribution automation and resiliency investments, predictive and preventative maintenance programs, seasonal readiness programs, emergency preparedness, and securing a reliable supply chain. Securing a reliable grid requires ongoing infrastructure investments in addition to investments to support new customer growth.
Balanced Energy Mix. APS strives to procure a balanced energy mix, and we believe this provides the greatest reliability at the lowest cost possible while increasing resiliency. We achieve reliability, in part, through a blend of dispatchable resources, such as natural gas and battery storage, that can provide energy when intermittent resources, such as wind and solar, are unavailable. APS regularly evaluates the best mix of resources based on a changing operating environment, including changes in generation technology, economics, and policy impacts.
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Currently, additional natural gas capacity is necessary to support reliable service and meet increasing energy needs. However, at this time existing natural gas pipelines into Arizona are fully committed. As a result, in July 2025, APS executed a gas transportation precedent agreement to secure a long-term supply of additional natural gas transportation. The new pipeline is expected to be operational by late 2029 and will be owned and operated by a third party. In July 2026, APS announced plans to convert two units at Cholla to natural gas, adding approximately 380 MW of gas-fired generation. The plan is subject to change pending the comparison to other generation sources that APS is considering in its evaluation of the 2025 ASRFP. The plan contemplates that construction on the gas conversion would begin in 2028 with a targeted in-service date in 2029. In addition to the planned Cholla gas conversion, APS plans to add up to 2,000 MW of flexible natural gas generation to its portfolio, designed to help meet the growing around-the-clock energy needs in Arizona. APS continues to explore additional development opportunities to meet Arizona’s growing needs.
Palo Verde, one of the nation’s largest carbon-free energy resources, serves as a foundational part of APS’s resource portfolio. The plant is a critical asset to the Southwest, generating more than 32 million MWh – enough power for roughly 3.4 million households, or approximately 8.5 million people. Its continued operation is important to a carbon-neutral future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy. APS owns or leases 29.1% of Units 1, 2, and 3 Palo Verde. In June 2025, APS entered into agreements to purchase two of the three leased interests in Unit 2. The two subject leased interests represented approximately 7% or 94 MW of Unit 2. The transaction closed in September 2025, leaving one remaining lease for approximately 5.2% of Unit 2 that expires in 2033. See Note 9 for more information. The 2025 Rate Case includes pro forma adjustments to account for these acquisitions.
In March 2026, APS announced its intention to renew the operating licenses for all three units at Palo Verde, which would extend operations from the mid-2040s through the mid-2060s. APS continues to evaluate and pursue options for reliably serving growing customer energy needs and demand.
Wildfire Efforts. Wildfire safety remains a critical focus for APS and other utilities. APS has increased investment in fire mitigation efforts to clear defensible space around its infrastructure, continue ongoing system upgrades, build partnerships with government entities and first responders, and educate customers and communities. APS also increased spend on grid technology to enable fast-trip relay response, also known as Enhanced Powerline Safety Settings. These programs contribute to customer reliability, fire ignition avoidance, responsible forest management, and safe communities. With wildfire events occurring across the U.S. and North America over the last few years, APS has been devoting and intends to continue to devote substantial efforts to analyzing and developing enhancements to its systems and processes to mitigate fire risk within its service territory and communities, including by hardening our infrastructure, deploying new technologies where appropriate, increasing situational awareness, implementing operational changes, and enhancing our wildfire response capabilities.
APS uses fire modeling software to identify and calculate risk and target future system improvement investments such as fire-resistant pole wrapping, wood to steel pole conversions, and additional remote-controllable field devices like reclosers and switches. In 2024, APS began installing a system of artificial intelligence-based fire sensing cameras with the ability to detect and alert on fire ignitions. These alerts are sent both to APS and fire response dispatch centers to speed fire response in APS’s service territory regardless of the cause of the fire. APS also implemented a public safety power shutoff (“PSPS”) program on certain feeders that began in the 2024 fire season, leveraging real-time analysis of weather and environmental factors, such as temperature, humidity, fuel moisture levels, and
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wind, provided by APS field sensors and the modeling software. APS has educated and will continue education outreach to customers and communities that may potentially be impacted by the PSPS program.
APS was selected by DOE’s Grid Deployment Office (“GDO”) to receive up to $70 million in federal money for fire mitigation and grid infrastructure projects. This funding is part of the GDO’s Grid Resilience and Innovation Partnership Program and is contingent on APS negotiating and executing final grant agreements with GDO. Additionally, on May 12, 2025, the Arizona governor signed into law a bill that requires Arizona electric utilities to develop and seek approval for wildfire mitigation plans and defines the standard of care with respect to wildfire-related claims by reference to such plans. Pursuant to that legislation, APS submitted its Comprehensive Wildfire Mitigation Plan to the Arizona Department of Forestry and Fire Management for review and approval. The wildfire mitigation plan was approved on May 7, 2026. APS continues to evaluate policy and regulatory options, as well as insurance programs, to mitigate the impact of wildfire events.
Affordable
We are committed to keeping bills as low as possible for our customers while maintaining high levels of reliability. Inflation has dramatically impacted the cost of goods and services in recent years, as shown by the Consumer Price Index for All Urban Consumers (“CPI-U”), which from 2018 through 2024 rose nationally 24.9% and 32.1% in Phoenix. Despite this, APS’s average residential rates remained well-below those inflation figures, rising 16.2% for the same period according to the U.S. Energy Information Administration. Inflation has recently reached its highest level since 2023, with CPI-U rising 4.2% nationally in the 12 months ended May 2026 and 3.0% in Phoenix over the 12 months ended April 2026. As a result of increased tariffs and supply chain constraints, APS amended several of its agreements from its ASRFP issued in 2023 to mitigate these cost impacts. However, APS remains cautious of potential price increases as a result of ongoing geopolitical events and current and proposed tariffs, which could lead to higher costs and supply chain constraints, while also continuing to monitor the impact of the U.S. Supreme Court’s recent decision regarding the validity of certain tariffs and any other related executive or legislative action.
APS’s customer affordability initiative includes internal opportunities, such as training and mentoring employees on identifying efficiency opportunities; maintaining inventory to take advantage of lower pricing and avoid expediting fees; entering into long-term contracts to hedge against price volatility, which has allowed APS to mitigate against procurement spend on critical items such as transformers; and implementing automation technologies to enhance efficiencies and increase data-oriented decision making. The customer affordability initiative also includes external opportunities, including a portfolio of customer programs designed to help customers reduce and manage their bills. In the 2025 Rate Case, APS is also seeking to reduce cross-subsidization of customer classes and ensure that growth pays for growth by requesting modifications to its cost allocation methodologies. APS continues to seek opportunities to streamline its business processes, mitigate cost increases, increase employee retention, and improve customer satisfaction.
APS’s IRP and competitive ASRFP processes serve important roles in providing reliable and affordable energy to APS’s customers. The IRP process helps identify the amount and type of resources required to reliably meet customer needs, while the ASRFP process seeks to meet those needs in a competitive manner based on cost, ability to meet system requirements, and commercial viability.
APS has seen increasing demand from large load customers in recent years. In the 2025 Rate Case, APS requested adjustments to rate designs and modification of cost allocation methodologies to ensure
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growth pays for growth and reduce cross-subsidization by customer classes. In line with the 2025 Rate Case, APS has developed an approach it believes will allow for these large load customers to fund the incremental infrastructure needed to serve them through long-term contracts where they cover capital costs and assume development risks, accelerating their path to service and ensuring those infrastructure costs are borne by those customers rather than residential or small business customers.
There are also external opportunities that allow APS to deliver more affordable energy to customers, such as APS’s participation in western energy markets and programs. APS participated in market design and tariff development of Markets+, a day-ahead and real-time market offering from the Southwest Power Pool. The Markets+ tariff was filed with FERC on March 29, 2024 and was approved on January 16, 2025. APS is a funding party to the implementation phase of Markets+ and expects to go live in the market in late 2027 or early 2028. In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool and plans to transition to full-binding participation in 2027. These regional efforts are driven by the objectives of reducing customer cost and improving reliability. APS will continue to participate in the Western Energy Imbalance Market (“WEIM”) as a tool for creating savings for APS’s customers from the real-time only, voluntary market for as long as feasible leading up to the transition to Markets+. APS expects that its participation in the WEIM and future participation in Markets+ will lower its fuel and purchased-power costs, improve situational awareness for systems operations in the Western Interconnection, and improve integration of APS’s resources.
Resource Planning—Prioritizing Reliability and Affordability
APS remains focused on providing reliable energy at the lowest cost possible while striving to lower emissions over time and continues to look for opportunities to support reliability through traditional dispatchable resources, such as gas and the potential extension of coal beyond 2031. APS’s diverse portfolio of existing and planned resources includes biomass, biogas, coal, energy storage, geothermal, natural gas, nuclear, solar, and wind. Every three years, APS performs an IRP, a comprehensive study to identify what resources will be necessary to safely, reliably, and affordably meet the demand and energy needs of its customers over the next 15 years. In November 2023, APS released its latest IRP, which identified forecasted customer demand and energy needs growing at an unprecedented rate. In developing the IRP, APS considered how factors such as forecasted economic growth, impacts from weather, and new resource technology availability impact the amount and type of resources required to reliably and affordably meet customer needs. These factors, among others, were used to develop a plan that identified a balanced mix of diverse energy-generating resources to reliably serve customers’ future energy needs. APS expects to file its next IRP on October 30, 2026, which will provide an updated view on the resource types and volumes necessary to maintain reliability for a rapidly expanding customer base. To help ensure competitive costs for resources procured by APS, APS regularly issues competitive bid solicitations through the ASRFP process, with the most recent ASRFP being issued in 2025. These ASRFPs are open to bids for all resource types, including customer-scale (behind the meter) and utility-scale (in front of the meter) resources.
APS selects projects out of ASRFPs based on cost, ability to meet system requirements, and commercial viability, taking into consideration timing and likelihood of successful contracting and development. Guided by IRP-established timelines and quantities, APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the ASRFP process. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection to the electric grid. Consistent with recent ASRFPs, APS remains focused on contracting for resources that can withstand supply chain pressures and
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volatility and seeks a balanced portfolio that is resilient to other external pressures, including those arising from the macroeconomic and geopolitical environment.
In terms of recent solicitations, APS issued an ASRFP on June 30, 2023, pursuant to which APS procured 3,606 MW of battery storage, 517 MW of natural gas, 2,649 MW of solar, and 500 MW of wind resources expected to be in service from 2026 to 2028. APS issued another ASRFP on November 20, 2024, pursuant to which it signed an amendment and extension to each of two existing gas tolling agreements, securing 600 MW under each agreement through 2038 and 2046, respectively. The scope of projects being negotiated out of the 2024 ASRFP reflects both the expanse of the 2023 ASRFP and the reality of adjusting to tariffs and changing federal policy.
In its most recent ASRFP, issued on November 19, 2025, APS is seeking at least 1,000 MW of resources that can reach commercial operation between 2029 and 2031, but APS will also consider projects that can achieve commercial operation earlier or later.
APS has an aspirational goal to be carbon-neutral by 2050. This means that for any GHG emissions still produced by our generation resources as of 2050, we will aim to offset these emissions elsewhere. This goal reflects APS’s interest in new generation and energy storage innovation and market transformations that address carbon emissions, while relying on the IRP and ASRFP processes to help determine the path forward.
Customer-Focused
Serving customers with excellence is foundational to APS’s business and remains our core focus as we adapt to evolving customer needs and emerging technology. Recognizing that every employee impacts our customer experience, we continue to provide information, tools, and resources enabling our teams to design, develop, and implement enhancements to improve our customer experience.
APS’s 24/7 call center answers more than 75% of customer calls within 30 seconds, and our mobile platforms enable our customers to quickly and easily find the information they need when they need it. We seek to provide relevant and valuable options for customers to manage their bill, including through rate plan options, programs that help them save energy and money, and alerts and notifications that help keep them aware of outages, payments, and usage. APS has a high-bill analyzer tool enabling phone advisors to provide customers with specific, customized guidance based on their actual usage and habits. For customers experiencing higher-than-expected bills, APS’s high-bill analyzer tool allows phone advisors to provide specific, customized guidance based on a customer's actual energy-use patterns.
Additionally, APS offers a variety of customer assistance resources, including income-qualified bill discounts of up to 60% for eligible customers, flexible payment arrangements and emergency utility bill assistance. To ensure customers are aware of and connected to these resources, APS partners with nearly one hundred community action agencies across our service territory, providing training and support to representatives who serve our shared customers. Through these partnerships and programs, APS works to ensure assistance is available to customers when they need it most.
Developing Technologies
New Nuclear Generation. Along with other Arizona electric utilities, APS is exploring additional nuclear generation to provide around-the-clock carbon-free energy to meet rising energy demands in Arizona. APS has been monitoring emerging nuclear technologies, ranging from newer proposed and
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installed versions of large-scale reactors to small modular nuclear reactors. Small modular nuclear reactors are typically designed to generate 300 MW or less of energy per unit compared to, for example, the 1,400 MW per unit generated at Palo Verde. The Arizona electric utilities have begun preliminary exploration of a potential site for additional nuclear energy for Arizona.
Long Duration Energy Storage. Continued technological innovation in long duration energy storage, which represents storage products which provide more than four hours of service, has led to decreasing cost of these solutions and an increase in their procurement, development, and deployment. These solutions include lithium and non-lithium battery chemistries, alternative natural gas-fired fuel cells and turbine units, and pumped hydropower. We will continue to evaluate these technologies and their ability to provide reliability, affordability, and balance to our portfolio.
Carbon Capture. CCS technologies can isolate carbon dioxide and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. CCS technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could potentially reduce carbon emissions from fossil fuel-fired generation.
Artificial Intelligence. To address the rapid advancement of AI technology risks and opportunities, APS has developed an AI strategy to responsibly utilize AI to advance our business strategy, enhance customer and employee experiences, and optimize operational reliability. At the core of our AI strategy is a focus on cultural transformation and workplace adoption of AI skills, supported by a robust governance model that guides the development of policies and strategies for the execution of AI projects at the Company. To ensure compliance with data security, reliability requirements, and our Code of Ethical Conduct, governance and oversight are provided by leadership and experts from our information technology, cybersecurity, human resources, ethics, supply chain, legal, and nuclear generation teams.
Regulatory Overview
2025 Rate Case
On June 13, 2025, APS filed the 2025 Rate Case application with the ACC seeking a net base rate increase of $579.5 million, which represents a 13.99% net increase. The requested net increase addresses a total base revenue deficiency of $662.4 million, offset by proposed adjustor transfers of cost recovery to base rates.
The 2025 Rate Case application includes the following proposals:
•a test year comprised of the 12-month period ended on December 31, 2024, including certain pro forma adjustments;
•12 months of post-test year plant placed into service from January 1, 2025 through December 31, 2025;
•an original cost rate base of $12.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
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•the following proposed capital structure and costs of capital:
Capital Structure Cost of Capital
Long-term debt 47.65 % 4.26 %
Common stock equity 52.35 % 10.70 %
Weighted-average cost of capital 7.63 %
•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•a rate of $0.043881 per kWh for the portion of APS’s base rates attributable to fuel and purchased power costs;
•adjustments to rate designs, including direct assignment of costs, to reduce cross-subsidization by certain customer classes;
•modification of cost allocation methodologies based on customer growth to ensure customers causing new production costs are covering those costs through rates, along with corresponding changes to adjustor mechanisms, such as for fuel and purchased power;
•implementation of a FRAM to assist with reducing regulatory lag and allow for rate gradualism;
•elimination of the LFCR following the first annual adjustment pursuant to the FRAM; and
•modification to the SRB due to the FRAM proposal.
On March 2 and March 18, 2026, the ACC Staff, RUCO, and other intervenors filed their initial written testimony with the ACC. ACC Staff’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $525.2 million total base revenue increase, (ii) a 9.55% to 9.80% return on equity, (iii) a 0.20% return on the increment of fair value, and (iv) 12 months of post-test year plant. RUCO’s testimony includes the following recommendations, among others, depending on the approval of APS’s proposed FRAM, (i) a $200.2 to $278.1 million total base revenue increase, (ii) a 9.00% to 9.20% return on equity, (iii) a 0.0% return on the increment of fair value, and (iv) 0 to 12 months of post-test year plant.
On April 3, 2026 , APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony are as follows:
•a total revenue requirement increase of $694.2 million, or a net revenue requirement increase of $611.3 million after adjustor transfers;
•maintaining a return on equity request of 10.7%;
•reducing the return on the increment of fair value from 1.0% to 0.9%;
•maintaining a post-test year plant request of 12 months and updating the impacted projects, including Ironwood solar and Sundance; and
•an integrated set of FRAM modifications that are intended to be evaluated together:
◦allowing for an earnings test “deadband” range of +/- 40 basis points to APS’s authorized return before an adjustment to the FRAM would be required;
◦limiting projected plant to six months;
◦elimination of the SRB and TEAM following the first annual adjustment pursuant to the FRAM;
◦retention of the 120-day review and challenge period; and
◦elimination of the interim rate reset by accepting Commission approval prior to implementation (subject to an automatic reversion provision).
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On May 1, 2026, ACC Staff, RUCO, and other intervenors filed their surrebuttal testimonies with the ACC. The ACC Staff adjusted their initial recommendation to a $506.5 million total base revenue increase and additional revisions to the Company’s FRAM proposal, including the continued recommendation for an earnings test “deadband” range of +/- 50 basis points.
On May 11, 2026, APS filed its rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies. APS’s rejoinder testimony included adjustments to the proposed schedule for the annual FRAM filing and a reduction of the total revenue requirement increase to $691.6 million, representing a revenue requirement increase, net of adjustor transfers, of $608.7 million. All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.
APS requested that the increase become effective in the second half of 2026. The hearing concluded on July 7, 2026. After the conclusion of the hearing, the Administrative Law Judge overseeing the hearing issued a procedural order outlining briefing schedules and other next steps in the proceedings. The order noted that the case is anticipated to be resolved before the end of this year. APS cannot predict the outcome of its request nor when the 2025 Rate Case will be decided by the ACC.
2022 Rate Case
On October 28, 2022, APS filed an application with the ACC (the “2022 Rate Case”) for an increase in retail base rates, and on January 25, 2024, an Administrative Law Judge issued a ROO, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).
On February 22, 2024, the ACC approved the 2022 Rate Case ROO with certain amendments that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an ASRFP, and (viii) recovery of all DSM costs through the DSM Adjustment Charge (“DSMAC”) rather than through base rates.
The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.
Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the GAC for solar customers, the SRB, and Coal Community Transition funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, AriSEIA, SEIA, and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. A limited rehearing was held October 28 through November 1, 2024. Following the limited rehearing, an Administrative Law Judge issued the Limited Rehearing ROO on December 3, 2024, which 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
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of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the ACC’s December 17, 2024 decision on the rehearing. The ACC has taken no action on these requests. In addition, each of these parties has subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC’s decisions regarding the GAC and on rehearing. On February 25, 2026, parties provided oral arguments before the Court of Appeals. On June 16, 2026, the Arizona Court of Appeals found that the GAC and related increases for residential solar customers were imposed by the ACC without adequate notice or opportunity to be heard. APS has since moved for reconsideration of this decision and, if reconsideration is not successful, plans to seek further review of this decision before the Arizona Supreme Court. APS cannot predict the outcome of these proceedings, but does not expect the outcome will have a material impact on APS’ financial position, results of operations, or cash flows.
Regulatory Lag Docket
On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates. On December 3, 2024, the ACC approved a policy statement regarding formula rate plans. The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases. On March 28, 2025, RUCO, the ALCG, and an individual customer filed a lawsuit challenging the ACC’s authority to issue the formula rate policy statement outside of Arizona’s formula rulemaking process. On June 13, 2025, the lawsuit challenging the ACC’s formula rate policy was dismissed by the Superior Court of Maricopa County. Following the dismissal, the plaintiffs filed an appeal with the Arizona Court of Appeals as well as a Petition for Special Action with the Arizona Supreme Court. The Supreme Court declined to exercise jurisdiction on the Petition for Special Action. The plaintiffs also filed a Petition for Special Action with the Arizona Court of Appeals, which has accepted jurisdiction to determine whether the case should be remanded back to the Superior Court for expedited consideration of the merits. On November 21, 2025, the Arizona Court of Appeals ruled that the issue should be remanded back to the Superior Court to determine whether the ACC’s formula rate policy must go through a formal rulemaking process. In response, APS, the ACC, and several other Arizona utility companies filed petitions for review of the Court of Appeals decision with the Arizona Supreme Court. That petition was denied on May 8, 2026, which will return the litigation to the Superior Court of Maricopa County for further proceedings on the merits of whether the ACC’s issuance of the formula rate policy statement complied with the Arizona Administrative Procedure Act. APS cannot predict the outcome of this matter or the impact (if any) it may have on other proceedings.
See Note 7 for more information regarding these and additional regulatory matters.
Captive Insurance Cell
Pinnacle West is the primary beneficiary of a protected cell captive insurance cell. The Captive provides insurance coverage to Pinnacle West and our subsidiaries that supplements commercial and mutual insurance coverage. 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 9. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments.
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Tax Incentives
The IRA significantly expanded the availability of tax credits for investments in clean energy generation technologies and energy storage. Key provisions included (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a PTC in lieu of the ITC beginning in 2022; (ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023; (iii) introduction of technology neutral clean energy ITCs and PTCs beginning in 2025; and (iv) introduction of a new Nuclear PTC, available from 2024 through 2032.
On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The OBBBA curtailed several clean energy tax credits initially passed in the IRA, including a new phase out deadline for wind and solar ITCs and PTCs that requires projects to either begin construction within one year of enactment or be placed in service by December 31, 2027. Additionally, the OBBBA contained provisions restricting clean energy projects, including energy storage, which begin construction after December 31, 2025, and receive “material assistance from a prohibited foreign entity,” from being eligible for clean energy ITCs or PTCs.
The Company believes that its projects which are currently under construction will continue to qualify for IRA tax credits. See Note 5 for information on Palo Verde’s Nuclear PTC. The Company is continuing to analyze the OBBBA and is awaiting regulations and other guidance as to the application of these new rules to projects not currently under construction.
Financial Strength and Flexibility
We believe that Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures are anticipated to be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Other Subsidiaries
PNW Power
PNW Power holds certain investments and assets that were previously held by BCE, a former subsidiary of Pinnacle West that was sold in 2024. PNW Power’s investments include TransCanyon, a 50/50 joint venture that was formed in 2014 with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. TransCanyon is pursuing independent electric transmission opportunities within the 11 U.S. states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the TransCanyon partners’ utility affiliates. These opportunities include the proposed 500-kV Cross-Tie transmission project (the “Cross-Tie Project”), which includes a 214-mile transmission line connecting Utah and Nevada that is intended to help improve grid reliability and relieve congestion on other transmission lines. On December 18, 2025, the Department of Interior Bureau of Land Management issued a Record of Decision permitting the development of Cross-Tie Project, which became non-appealable in late January 2026.
PNW Power’s investments also include minority ownership positions in two wind farms operated by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms. Clear Creek achieved commercial operation in May 2020; however, in the fourth
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quarter of 2022, PNW Power’s equity method investment was fully impaired. Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under long-term PPAs. PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.
El Dorado
El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. In particular, El Dorado has committed to and/or holds the following:
•$25 million investment in the Energy Impact Partners fund, of which approximately $21 million has been funded as of June 30, 2026. Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.
•$25 million investment in Copper Sky, previously AZ-VC, of which approximately $19 million has been funded as of June 30, 2026. Copper Sky is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately-held early stage and emerging growth technology companies and businesses primarily based in Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona.
•$7.5 million investment in Westly Seed Fund, of which approximately $2 million has been funded as of June 30, 2026. Westly Seed Fund is focused on supporting entrepreneurs involved in the energy, mobility, building, and industrial sectors.
•Equity investment in SAI, a private corporation that manufactures electrical switchgear equipment used by data centers. El Dorado accounts for this investment under the equity method and has an investment carrying value of approximately $34 million as of June 30, 2026.
The remainder of these investment commitments will be contributed by El Dorado as each investment fund selects and makes investments.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For 2025, retail electric revenues were 95% of our total operating revenue. For 2023 through 2025, retail electric revenues averaged approximately 94% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Our revenues are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand, and prices.
Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.1% for the period ended June 30, 2026 compared with the prior-year period. For the three
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years through 2025, APS’s customer growth averaged 2.2% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2026 and the average annual growth to be in the range of 1.5% to 2.5% through 2030 based on anticipated steady population growth in Arizona during that period.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 3.9% for residential customers, 13.6% for commercial and industrial customers, 3.9% for residential customers, and 9.5% for all retail customers for the period ended June 30, 2026 compared with the prior-year period. While strong sales to commercial and industrial customers continue to be driven by the ramp-up of new data center and large manufacturing customers, the main drivers of increased revenues for this period were a surge in residential usage during April and May, including on days with normal weather conditions, following strong weather-driven demand caused by a record-setting March heat wave in Arizona in the first quarter of 2026 and steady customer growth, which was only partially offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation. Due to the growth of large load customers as a proportion of our business, in the first quarter of 2025, we updated our procedures with respect to estimates of unbilled revenues. This resulted in a downward adjustment to unbilled revenues in that quarter, which contributes approximately 0.9% to 2026 year-to-date sales growth as compared to the same period last year.
For the three years through 2025, annual retail electricity sales growth averaged 3.9%, adjusted to exclude the effects of weather variations. Due to the expected growth of several data centers and large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 4.0% to 6.0% for 2026 and that average annual growth will be in the range of 5.0% to 7.0% through 2030, including the effects of customer conservation, energy efficiency, and distributed renewable generation, but excluding the effects of weather variations. These projected sales growth ranges include the impacts of several data centers and large manufacturing facilities, which are expected to contribute to 2026 growth in the range of 3.0% to 5.0% and to average annual growth in the range of 4.0% to 6.0% through 2030.
Longer term, APS has been preparing for and can serve significant load growth from residential and business customers. On top of these existing growth trends, APS is also receiving incremental requests for service from large load customers with very high energy demands that persist virtually around-the-clock, such as data centers for AI and large manufacturers. These incremental requests for service by large load customers far exceed available generation and transmission resource capacity in the Southwest region for the foreseeable future. Because of the high growth in demand for such projects, APS has developed a queue that identifies and prioritizes projects while maintaining system reliability and affordability for existing APS customers. APS is also exploring available options for developing additional electric generation and transmission to meet these projections of future customer needs as a part of the company’s “growth pays for growth” strategy, such as long-term contracts with large load customers to pay for the costs associated with the incremental infrastructure needed to provide service without compromising reliability and affordability for existing customers.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as macroeconomic conditions, current and future economic, regulatory, business, and other conditions, such as the Arizona housing market, customer growth, usage patterns and energy conservation, slower ramp-up of and/or fewer large data centers and manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs and growth in DG, responses to retail price changes, changes in regulatory standards, and impacts of new and existing laws and regulations, including environmental laws and regulations. Based on past experience, a 1% variation in our annual residential and small commercial and industrial kWh sales projections under
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normal business conditions can result in increases or decreases in annual net income of approximately $25 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $7 million.
Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Our experience indicates that typical variations from normal weather can result in increases and decreases in annual net income of up to $30 million. However, since 2020, extreme weather events, such as record-setting summer heat and decreased annual precipitation in our service territory, have resulted in increases in annual net income that are more than historically typical on average.
Fuel and Purchased Power Expenses. Fuel and purchased power expenses included on our Condensed Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and DSM related expenses (which are mostly offset by the same amount of operating revenues) and other factors.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and increases in intangible assets and changes in depreciation and amortization rates. See “Liquidity and Capital Resources” below for information regarding the planned additions to our facilities.
Pension and Other Postretirement Non-Service Credits, Net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, mortality assumptions and assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them, as necessary. See Note 8.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by changes in plant balances related to new investments and improvements to existing facilities, the value of property in service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 9.6% of the assessed value for 2025, 9.7% for 2024, and 10.0% for 2023.
Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions, certain credits and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. See Note 6 for further details. The primary factors affecting borrowing levels are
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expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. AFUDC offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed into service.
RESULTS OF OPERATIONS
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of retail and wholesale sales supplied under traditional cost-based regulation and related activities and includes electricity generation, transmission, and distribution. Our reportable segment activities are conducted through our wholly-owned subsidiary, APS. All other operating segment activities are insignificant to Pinnacle West.
Operating Results – Three-month period ended June 30, 2026, compared with three-month period ended June 30, 2025.
Our consolidated net income attributable to common shareholders for the three months ended
June 30, 2026 was $179 million, compared with consolidated net income attributable to common shareholders of $193 million for the prior-year period. The results reflect a decrease of approximately $14 million, primarily as a result of higher interest charges, higher depreciation and amortization expenses mostly due to increased plant additions, partially offset by operations ceasing at Cholla, and lower transmission service revenues. These negative factors were partially offset by the favorable impacts of the effects of weather, increased customer usage, customer growth, lower operations and maintenance expenses, and lower income taxes. Customer growth in turn was partially offset by the related pricing and the impacts of energy efficiency.
The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated (dollars in millions):
Pinnacle West Consolidated APS Consolidated
Three Months Ended June 30, Three Months Ended June 30,
2026 2025 Net Change 2026 2025 Net Change
Operating revenues $ 1,456 $ 1,359 $ 97 $ 1,456 $ 1,359 $ 97
Fuel and purchased power (558) (477) (81) (558) (477) (81)
Operating revenues less fuel and purchased power (a) 898 882 16 898 882 16
Operations and maintenance (283) (287) 4 (281) (285) 4
Depreciation and amortization (243) (229) (14) (243) (229) (14)
Taxes other than income taxes (62) (58) (4) (62) (58) (4)
Allowance for equity funds used during construction 17 15 2 17 15 2
Pension and other postretirement non-service credits, net 5 4 1 5 4 1
Other income and (expense), net 2 7 (5) (8) (2) (6)
Interest charges, net of allowance for borrowed funds used during construction (122) (102) (20) (97) (80) (17)
Income taxes (31) (35) 4 (36) (39) 3
Less: Net income attributable to noncontrolling interests (2) (4) 2 (2) (4) 2
Net Income Attributable to Common Shareholders $ 179 $ 193 $ (14) $ 191 $ 204 $ (13)
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(a) Operating revenues less fuel and purchased power is a non-GAAP financial measure. As reconciled in the table above, this amount is derived by the difference between the GAAP financial statement line item Operating revenues less the GAAP financial statement line item Fuel and purchased power as presented on the Condensed Consolidated Statements of Income. Operating revenues, less fuel and purchased power is used by Pinnacle West to assess whether customer revenues adequately cover fuel and purchased power costs. This metric is not defined by GAAP and may differ from similar measures used by other companies. This measure is not a substitute for operating income under GAAP.
Operating revenues less fuel and purchased power. Operating revenues less fuel and purchased power expenses were $16 million higher for the three months ended June 30, 2026 compared with the prior-year period. The following table summarizes the major components of this change (dollars in millions):
Increase (Decrease)
Operating revenues Fuel and purchased power Net change
Effects of weather $ 27 $ 8 $ 19
Higher retail revenues due to changes in usage patterns, and customer growth, partially offset by the related pricing and impacts of energy efficiency 49 31 18
LFCR revenue (Note 7) 3 — 3
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 36 40 (4)
Lower transmission revenues (Note 7) (12) — (12)
Lower renewable energy regulatory surcharges, partially offset by lower operations and maintenance costs (13) 3 (16)
Miscellaneous items, net 7 (1) 8
Total $ 97 $ 81 $ 16
Operations and maintenance. Operations and maintenance expenses decreased $4 million for the three months ended June 30, 2026 compared with the prior-year period primarily due to:
•a decrease of $18 million related to costs for renewable energy programs and similar regulatory programs, which are partially offset in operating revenues and purchased power;
•a decrease of $1 million related to non-nuclear generation costs, primarily due to lower planned outages;
•an increase of $2 million related to information technology costs;
•an increase of $2 million related to employee benefit costs;
•an increase of $4 million related to nuclear generation costs;
•an increase of $4 million related to transmission, distribution, and customer service costs;
•an increase of $5 million related to corporate resource costs; and
•a decrease of $2 million for other miscellaneous factors.
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Depreciation and amortization. Depreciation and amortization expenses were $14 million higher for the three months ended June 30, 2026 compared to the prior-year period, primarily due to increased plant in service, partially offset by operations ceasing at the Cholla plant.
Other income and expense, net. Other income and expense, net was $5 million lower for the three months ended June 30, 2026 compared to the prior-year period, primarily due to lower PSA interest income and higher other expenses, partially offset by investment gains in the Captive. The difference between APS’s and Pinnacle West’s other income and expense, net is primarily related to Pinnacle West’s investment gains in the Captive.
Interest charges, net of allowance for borrowed funds and equity funds used during construction. Interest charges, net of allowance for funds used during construction, were $18 million higher for the three months ended June 30, 2026 compared to the prior-year period, primarily due to higher debt balances, partially offset by higher allowance for equity funds used during construction.
Taxes other than income taxes. Taxes other than income taxes were $4 million higher for the three months ended June 30, 2026, compared to the prior-year period, primarily due to higher plant balances.
Income taxes. Income taxes were $4 million lower for the three months ended June 30, 2026 compared with the prior-year period, primarily due to lower pre-tax income.
Operating Results – Six-month period ended June 30, 2026, compared with six-month period ended June 30, 2025.
Our consolidated net income attributable to common shareholders for the six months ended
June 30, 2026 was $211 million, compared with consolidated net income attributable to common shareholders of $188 million for the prior-year period. The results reflect an increase of approximately $23 million, primarily as a result of the effects of weather, increased usage and customer growth, lower operations and maintenance expenses, and higher transmission service revenues. Customer growth in turn was partially offset by the related pricing and the impacts of energy efficiency. These positive factors were partially offset by higher interest charges, lower other income mainly due to higher El Dorado other income recognized in the prior year, and higher depreciation and amortization expenses mostly due to increased plant additions and intangible assets, partially offset by operations ceasing at Cholla.
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The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated (dollars in millions):
Pinnacle West Consolidated APS Consolidated
Six Months Ended June 30, Six Months Ended June 30,
2026 2025 Net Change 2026 2025 Net Change
Operating revenues $ 2,605 $ 2,391 $ 214 $ 2,605 $ 2,391 $ 214
Fuel and purchased power (995) (857) (138) (995) (857) (138)
Operating revenues less fuel and purchased power (a) 1,610 1,534 76 1,610 1,534 76
Operations and maintenance (560) (587) 27 (554) (582) 28
Depreciation and amortization (483) (464) (19) (483) (464) (19)
Taxes other than income taxes (124) (117) (7) (124) (117) (7)
Allowance for equity funds used during construction 32 28 4 32 28 4
Pension and other postretirement non-service credits, net 9 7 2 9 7 2
Other income and (expense), net 1 22 (21) (10) 2 (12)
Interest charges, net of allowance for borrowed funds used during construction (238) (197) (41) (189) (159) (30)
Income taxes (32) (29) (3) (44) (36) (8)
Less: Net income attributable to noncontrolling interests (4) (9) 5 (4) (9) 5
Net Income Attributable to Common Shareholders $ 211 $ 188 $ 23 $ 243 $ 204 $ 39
(a) Operating revenues less fuel and purchased power is a non-GAAP financial measure. As reconciled in the table above, this amount is derived by the difference between the GAAP financial statement line item Operating revenues less the GAAP financial statement line item Fuel and purchased power as presented on the Condensed Consolidated Statements of Income. Operating revenues, less fuel and purchased power is used by Pinnacle West to assess whether customer revenues adequately cover fuel and purchased power costs. This metric is not defined by GAAP and may differ from similar measures used by other companies. This measure is not a substitute for operating income under GAAP.
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Operating revenues less fuel and purchased power. Operating revenues less fuel and purchased power expenses were $76 million higher for the six months ended June 30, 2026 compared with the prior-year period. The following table summarizes the major components of this change (dollars in millions):
Increase (Decrease)
Operating revenues Fuel and purchased power Net change
Effects of weather $ 57 $ 16 $ 41
Higher retail revenues due to changes in usage patterns, and customer growth, partially offset by the related pricing and the impacts of energy efficiency 93 55 38
Higher transmission revenues (Note 7) 15 — 15
LFCR revenue (Note 7) 6 — 6
Lower renewable energy regulatory surcharges, partially offset by lower operations and maintenance costs (22) 5 (27)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 61 61 —
Miscellaneous items, net 4 1 3
Total $ 214 $ 138 $ 76
Operations and maintenance. Operations and maintenance expenses decreased $27 million for the six months ended June 30, 2026 compared with the prior-year period, primarily due to:
•a decrease of $28 million related to costs for renewable energy programs and similar regulatory programs, which are partially offset in operating revenues and purchased power;
•a decrease of $15 million related to non-nuclear generation costs, primarily due to lower planned outages;
•a decrease of $5 million related to information technology costs;
•an increase of $4 million related to employee benefit costs;
•an increase of $6 million related to transmission, distribution, and customer service costs;
•an increase of $6 million related to nuclear generation costs;
•an increase of $9 million related to corporate resource costs; and
•a decrease of $4 million for other miscellaneous factors.
Depreciation and amortization. Depreciation and amortization expenses were $19 million higher for the six months ended June 30, 2026 compared to the prior-year period, primarily due to increased plant in service and intangible assets, partially offset by lower depreciation expense due to operations ceasing at the Cholla plant.
Other income and expense, net. Other income and expense, net was $21 million lower for the six months ended June 30, 2026 compared to the prior-year period, primarily due to lower other income from El Dorado, lower PSA interest income and higher other expenses. The difference between APS’s and Pinnacle West’s other income and expense, net is primarily related to Pinnacle West’s other income from El Dorado.
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Interest charges, net of allowance for borrowed funds and equity funds used during construction. Interest charges, net of allowance for funds used during construction, were $37 million higher for the six months ended June 30, 2026 compared to the prior-year period, primarily due to higher debt balances, partially offset by higher allowance for equity funds used during construction.
Taxes other than income taxes. Taxes other than income taxes for the for the six months ended June 30, 2026 were $7 million higher, compared to the prior-year period, primarily due to higher plant balances.
Income taxes. Income taxes were $3 million higher for the six months ended June 30, 2026 compared with the prior-year period, primarily due to higher pre-tax income, partially offset by higher tax credits.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order does not allow APS to pay common dividends if the payment would reduce its common equity ratio below 40%. Per the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. As of June 30, 2026, APS’s common equity ratio, as defined, was 51%. APS’s total shareholder equity was approximately $9.0 billion, and total capitalization, as calculated pursuant to the ACC order, was approximately $17.8 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $7.1 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.
Dividends to Pinnacle West from APS are also dependent on a number of factors including, among others, APS’s financial condition and free cash flow, the sources of which vary from quarter-to-quarter due in part to the seasonal nature of electricity demand in Arizona. APS’s sources of cash include cash from operations and external sources of liquidity, including long- and short-term external debt financing such as commercial paper, term loans and its revolving credit facility. Cash from operations is dependent upon, among other things, the rates APS may charge and the timeliness of recovering costs incurred through its rates and adjustor recovery mechanisms. Regulatory lag may delay recovery and affect operating cash flows. APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West. On December 17, 2024, the ACC issued a financing order approving a limit on yearly equity infusions equal to 2.5% of APS’s total 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 July 31, 2026, APS submitted an application to the ACC requesting to increase the long-term debt limit from $9.5 billion to $12 billion. APS cannot predict the outcome of this matter.
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Pinnacle West and APS maintain committed revolving credit facilities that enhance liquidity and provide credit support for accessing commercial paper markets. These credit facilities mature in 2031.
Pinnacle West has an ATM Program under which Pinnacle West may offer and sell Pinnacle West common stock and enter into forward sale agreements from time to time, subject to market conditions and other factors. Pinnacle West also has forward sale agreements from an equity offering in February 2024 in effect as of June 30, 2026. See “Financing Cash Flows and Liquidity—Equity Offerings” below and Note 13 for more information.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating, investing and financing activities (dollars in millions):
Pinnacle West Consolidated
Six Months Ended June 30,
2026 2025 Net Change
Net cash flow provided by operating activities $ 629 $ 663 $ (34)
Net cash flow used for investing activities (1,200) (1,253) 53
Net cash flow provided by financing activities 574 605 (31)
Net increase in cash and cash equivalents $ 3 $ 15 $ (12)
APS Consolidated
Six Months Ended June 30,
2026 2025 Net Change
Net cash flow provided by operating activities $ 688 $ 698 $ (10)
Net cash flow used for investing activities (1,188) (1,248) 60
Net cash flow provided by financing activities 503 561 (58)
Net increase in cash and cash equivalents $ 3 $ 11 $ (8)
Operating Cash Flows
Six-month period ended June 30, 2026 compared with six-month period ended June 30, 2025. Pinnacle West’s consolidated net cash provided by operating activities was $629 million in 2026 compared to $663 million in 2025, a decrease of $34 million in net cash provided, primarily due to $68 million in higher payments for fuel and purchased power costs, $35 million in higher interest paid on debt, net of amounts capitalized, and $14 million higher payments for other taxes paid; partially offset by $61 million higher cash receipts from electric revenues and $22 million in higher working capital, net. The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s lower interest paid on debt, net of amounts capitalized, and other changes in working capital.
Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income
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Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The expected minimum required cash contributions for the pension plan are zero for the next three years. However, while we do not expect to make any voluntary cash contributions in 2026, we are evaluating whether to make voluntary contributions in 2027 and 2028. The amounts of voluntary contributions, if any, will be determined as we continue to evaluate and assess our ongoing contribution strategy. Regarding contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2026 and do not expect to make any contributions in 2026, 2027 or 2028. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status.
Investing Cash Flows
Six-month period ended June 30, 2026 compared with six-month period ended June 30, 2025. Pinnacle West’s consolidated net cash used for investing activities was $1,200 million in 2026 compared to $1,253 million in 2025, a decrease of $53 million of cash used primarily related to a $70 million increase in contributions in aid of construction; partially offset by a $25 million increase in capital expenditures. See “Capital Expenditures” below for additional details.
Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years (dollars in millions):
Capital Expenditures
Estimated for the Year Ending December 31,
2026 2027 2028
APS
Generation:
Gas and Other Generation $ 635 $ 550 $ 490
Nuclear Generation 170 185 215
Renewables and Energy Storage 20 5 5
Distribution 765 795 750
Transmission 550 695 860
Other 460 420 380
Total APS $ 2,600 $ 2,650 $ 2,700
The estimated capital expenditures presented above do not include amounts related to the Cholla gas conversion project, which is currently expected to cost up to approximately $440 million. In addition, projected capital expenditures for entities other than APS are not included, as such amounts are expected to be immaterial.
Generation capital expenditures are comprised of various additions and improvements to APS’s resources, including nuclear plants, renewables and energy storage, additions and improvements to existing fossil fuel plants, as well as planned investments in new natural gas facilities. We are monitoring the status
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of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures are expected to be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Financing Cash Flows and Liquidity
Six-month period ended June 30, 2026 compared with six-month period ended June 30, 2025. Pinnacle West’s consolidated net cash provided by financing activities was $574 million in 2026 compared to $605 million in 2025, a decrease of $31 million in net cash provided primarily due to a net decrease of $775 million in short-term borrowings; partially offset by a $450 million decrease in long-term debt repayments and a $297 million increase in long-term borrowings.
APS’s consolidated net cash provided by financing activities was $503 million in 2026 compared to $561 million in 2025, a decrease of $58 million in net cash provided primarily due to a net decrease of $753 million in short-term borrowings and $200 million in lower equity infusions from the parent; partially offset by a $595 million increase in long-term borrowings and a $300 million decrease in long-term debt repayments.
Significant Financing Activities. On June 24, 2026, the Pinnacle West Board of Directors declared a dividend of $0.91 per share of common stock, payable on September 1, 2026, to shareholders of record on August 3, 2026.
On June 5, 2026, Pinnacle West contributed $100 million into APS in the form of an equity infusion. APS used this contribution to pay down short-term indebtedness consisting of commercial paper.
Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 6 for more information on available credit facilities.
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Equity Offerings. Pinnacle West entered into certain equity forward sale agreements in February 2024 and has an ATM Program under which Pinnacle West may offer and sell Pinnacle West common stock and enter into equity forward sale agreements from time to time, subject to market conditions and other factors. These agreements may be settled at Pinnacle West’s discretion by issuing shares of Pinnacle West common stock and receiving cash, if any, at the then-applicable forward sales price. See Note 13. The following table summarizes the activity relating to these forward sale agreements and the ATM Program as of June 30, 2026 (dollars in thousands, except price per share):
Forward Sale Agreements Number of Shares Forward Sales Price Per Share Aggregate Value
February 2024 Forward Sale Agreements
Initial Price 11,240,601 $ 64.51 (a) $ 725,131
Settlements
December 23, 2024 5,377,115 (b) $ 64.17 $ 345,049 (c)
September 4, 2025 243,186 (b) $ 63.12 $ 15,350 (c)
December 18, 2025 1,193,950 (b) $ 62.82 $ 75,004 (c)
ATM Program
Initial Price (e) 8,306,132 $ 97.38 (a) (d) $ 808,887
(a) Subject to certain adjustments.
(b) Physical delivery.
(c) Proceeds recorded in common equity on the Condensed Consolidated Balance Sheets.
(d) Weighted-average price for the total ATM Program.
(e) Does not include one forward sale agreement, whose effective date was July 6, 2026, relating to a total of $84 million, on a gross basis, of common stock, with a maturity date of July 3, 2028.
Other Financing Matters. See Note 10 for information related to the change in our margin and collateral accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. As of June 30, 2026, the ratio was approximately 62% for Pinnacle West and 51% 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.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of payment 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 and APS’s credit agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment if Pinnacle West or APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change covenant for credit facility borrowings.
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Credit Ratings
The ratings of securities of Pinnacle West and APS as of July 31, 2026, are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a potential downward revision to our credit ratings.
Moody’s Standard & Poor’s Fitch
Pinnacle West
Corporate credit rating Baa2 BBB+ BBB
Senior unsecured Baa2 BBB BBB
Commercial paper P-2 A-2 F3
Outlook Stable Stable Stable
APS
Corporate credit rating Baa1 BBB+ BBB+
Senior unsecured Baa1 BBB+ A-
Commercial paper P-2 A-2 F2
Outlook Stable Stable Stable
Contractual Obligations
Pinnacle West’s contractual obligations have not materially changed during the six months ended June 30, 2026 as compared to the 2025 Form 10-K, except as disclosed in Note 6 - “Debt and Liquidity Matters” and Note 11 - “Commitments and Contingencies” to the Combined Notes to condensed consolidated financial statements included in this report.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies and estimates since our 2025 Form 10-K. See “Critical Accounting Policies and Estimates” in Item 7 of the 2025 Form 10-K for further details about our critical accounting policies and estimates.
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OTHER ACCOUNTING MATTERS
See Note 3 for information relating to the following new accounting standards pending adoption:
•ASU 2024-03, Income Statement Reporting: Expense Disaggregation Disclosures, effective for us on December 31, 2027, with early adoption permitted.
•ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software: Targeted Improvements to the Accounting for Internal-Use Software, effective for us on January 1, 2028, with early adoption permitted.
•ASU 2025-09, Derivatives and Hedging: Hedge Accounting Improvements, effective for us on January 1, 2027, with early adoption permitted.
•ASU 2025-10, Government Grants: Accounting for Government Grants Received by Business Entities, effective for us on January 1, 2029, with early adoption permitted.
•ASU 2026-02, Environmental Credits and Environmental Credit Obligations, effective for us on January 1, 2028, with early adoption permitted.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trusts, other special use funds and benefit plan assets.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Notes 14 and 15), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning, coal reclamation, and benefit plan costs are recovered in regulated electricity prices.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
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The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions):
Six Months Ended June 30,
2026 2025
Balance at beginning of period $ (26) $ (42)
Decrease (increase) in regulatory asset (53) 59
Balance at end of period $ (79) $ 17
The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) as of June 30, 2026, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements” in Item 8 of our 2025 Form 10-K for more discussion of our valuation methods.
Source of Fair Value 2026 2027 2028 2029 2030 Total Fair Value
Observable prices provided by other external sources $ (23) $ (20) $ (4) $ 1 $ — $ (46)
Prices based on unobservable inputs (32) — — (1) — (33)
Total by maturity $ (55) $ (20) $ (4) $ — $ — $ (79)
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets (dollars in millions):
June 30, 2026Gain (Loss) December 31, 2025Gain (Loss)
Price Up 10% Price Down 10% Price Up 10% Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity $ 2 $ (2) $ 3 $ (3)
Natural gas 50 (50) 58 (58)
Total $ 52 $ (52) $ 61 $ (61)
(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 10 for a discussion of our credit valuation adjustment policy.
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