Pinnacle West Capital Corporation
02/25/2026 | Press release | Distributed by Public on 02/25/2026 07:27
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West's Consolidated Financial Statements and APS's Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. This discussion provides a comparison of the 2025 results with 2024 results. For the discussion of 2024 compared to 2023, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of Pinnacle West Capital Corporation's Annual Report on Form 10-K for the year ended December 31, 2024, which specific discussion is incorporated herein by reference. 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 Item 1A.
OVERVIEW
Business Overview
Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $30 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 1.4 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 secure resource adequacy, planning and procuring resources to ensure sufficient reserve margins, 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.
Additional natural gas capacity is necessary to support reliable service and meet increasing energy needs. However, existing natural gas pipelines into Arizona are currently 100% committed. As a result, in July 2025, APS executed a gas transportation precedent agreement to secure a long-term supply of natural gas. The new pipeline is expected to be operational by late 2029 and will be owned and operated by a third-party. See Note 14 for more information. APS also 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. This generation is expected to serve existing customers and business-as-usual growth through our competitive ASRFP process as well as a new subscription model for large load customers, like data centers and large manufacturers. This subscription model is a commercial construct designed to ensure growth pays for growth while protecting affordability for other customers.
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 12 for more information. APS's rate case application filed in 2025 (the "2025 Rate Case") includes pro forma adjustments to account for these acquisitions. 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 mitigating the risk associated with trees that could cause hazards, resulting in more of these trees being removed before they could cause outages or wildfires. These programs contribute to customer reliability, responsible forest management and safe communities. With wildfire events in Hawaii, California, and across 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 our 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 the additional real-time analysis provided by 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, Arizona Governor Hobbs 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. 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 moderated from earlier highs, with CPI-U rising 2.7% nationally and 2.2% in Phoenix over the 12 months ended December 2025. 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 current and proposed tariffs, which could lead to higher costs and supply chain constraints, while also monitoring the outcome of the recent U.S. Supreme Court's decision regarding the validity of certain tariffs.
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 growth pays for growth. In line with the 2025 Rate Case, APS has developed a subscription model 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 SPP. 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 October 2027. 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 or 2028. These regional efforts are driven by the objectives of reducing customer cost and improving reliability. Until the transition to Markets+, APS will continue to participate in the WEIM as a tool for creating savings for APS's customers from the real-time only, voluntary market. 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 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. 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 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 an existing gas tolling agreement, increasing it to 600 MW beginning in 2027 and extending the term to 2038 and is currently negotiating
additional agreements. 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 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 more than one million 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 recently introduced a high-bill analyzer tool enabling phone advisors to provide customers with specific, customized guidance based on their actual usage and habits.
Additionally, APS offers a customer assistance program, including up to a 60% bill discount for vulnerable customers, flexible payment arrangements, and emergency utility bill assistance. To ensure customers in need are connected to these programs, we partner with nearly one hundred community action agencies across our service territory to train representatives who serve our shared customers.
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 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 utilities have applied for a grant from DOE to begin preliminary exploration of a potential site for additional nuclear energy for Arizona. The grant could support a three-year site selection process and possible preparation of an early site permit application to NRC.
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 robust governance model that develops guidance, policies, and relevant sub-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 an 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;
•the following proposed capital structure and costs of capital:
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Capital Structure
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Cost of Capital
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Long-term debt
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47.65 | % | 4.26 | % | ||||||||||
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Common stock equity
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52.35 | % | 10.70 | % | ||||||||||
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Weighted-average cost of capital
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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.
APS requested that the increase become effective in the second half of 2026. The hearing for this rate case is currently scheduled to begin in May 2026. APS cannot predict the outcome of its request nor when the 2025 Rate Case will be decided by the ACC.
2022 Rate Case
On October 28, 2022, APS filed an application with the ACC (the "2022 Rate Case") for an increase in retail base rates, and on January 25, 2024, an Administrative Law Judge issued a ROO, as corrected on February 6, 2024 (the "2022 Rate Case ROO").
On February 22, 2024, the ACC approved the 2022 Rate Case ROO with certain amendments that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company's weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an ASRFP, and (viii) recovery of all DSM costs through the DSM Adjustment Charge ("DSMAC") rather than through base rates.
The ACC issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.
Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC's decision, such as the grid access charge ("GAC") for solar customers, the SRB, and Coal Community Transition funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association ("AriSEIA"), Solar Energy Industries Association ("SEIA"), and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. A limited rehearing was held October 28 through November 1, 2024. Following the limited rehearing, an Administrative Law Judge issued a ROO (the "Limited Rehearing ROO") on December 3, 2024. The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers. On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers. SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the ACC's December 17, 2024 decision on the rehearing. The ACC has taken no action on these requests. In addition, each of these parties have
subsequently filed an appeal to the Arizona Court of Appeals seeking review of the ACC's decisions regarding the GAC and on rehearing. APS cannot predict the outcome of these proceedings.
Regulatory Lag Docket
On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC's historical test year rules. The ACC requested comments and held two workshops exploring ways to reduce regulatory lag, including alternative ratemaking structures such as future test years, hybrid test years, and formula rates. On December 3, 2024, the ACC approved a policy statement regarding formula rate plans. The policy statement provides regulated utilities with the opportunity to propose formula rate plans in future rate cases. On March 28, 2025, the Residential Utility Consumer Office ("RUCO"), the Arizona Large Customer Group ("ALCG"), and an individual customer filed a lawsuit challenging the ACC's authority to issue the formula rate policy statement outside of Arizona's formula rulemaking process. On June 13, 2025, the lawsuit challenging the ACC's formula rate policy was dismissed by the Superior Court of Maricopa County. Following the dismissal, the plaintiffs filed an appeal with the Arizona Court of Appeals as well as a Petition for Special Action with the Arizona Supreme Court. The Supreme Court declined to exercise jurisdiction on the Petition for Special Action. The plaintiffs also filed a Petition for Special Action with the Arizona Court of Appeals, which has accepted jurisdiction to determine whether the case should be remanded back to the Superior Court for expedited consideration of the merits. On November 21, 2025, the Arizona Court of Appeals ruled that the issue should be remanded back to the Superior Court to determine whether the ACC's formula rate policy must go through a formal rulemaking process. In response, APS, the ACC, and several other Arizona utility companies filed petitions for review of the Court of Appeals decision with the Arizona Supreme Court, which is pending at this time. APS cannot predict the outcome of this matter.
See Note 8 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 12. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments.
Tax Incentives
The Inflation Reduction Act of 2022 ("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 PTC for nuclear energy produced by existing nuclear energy plants, 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 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 $20 million has been funded as of December 31, 2025. Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.
•$25 million investment in AZ-VC, of which approximately $16 million has been funded as of December 31, 2025. AZ-VC is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately-held early stage and emerging growth technology companies and businesses primarily based in Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona.
•$7.5 million investment in Westly Seed Fund, of which approximately $2 million has been funded as of December 31, 2025. 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 $21 million as of December 31, 2025.
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 2.4% for the period ended December 31, 2025 compared with the prior-year period. For the three 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 5.0% for the period ended December 31, 2025 compared with the prior-year period. While steady customer growth was somewhat offset by lower usage among residential customers, energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of increased revenues for this period were continued strong sales to commercial and industrial customers and the continued ramp-up of new data center and large manufacturing customers. As large load customers, such as data centers and large manufacturers, have continued to grow as a proportion of our
business, we have updated our procedures with respect to estimates of unbilled revenues for our customer classes. As a result, we made an adjustment in the first quarter of 2025 to recalibrate accrued unbilled revenues, offsetting year-to-date sales growth by 0.4%.
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 initiatives, but excluding the effects of weather variations. These projected sales growth ranges include the impacts of several data centers and large manufacturing facilities, which are expected to contribute to 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 securing additional electric generation and transmission to meet these projections of future customer needs, including a new subscription model for large load customers. The subscription model is part of the company's "growth pays for growth" strategy where large load customers would enter into a long-term special contract 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 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 $20 million. However, since 2020, extreme weather events, such as record-setting summer heat and decreased annual precipitation in our service territory, have resulted in increases in annual net income that are more than historically typical, on average.
Fuel and Purchased Power Expenses. Fuel and purchased power expenses included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and DSM related expenses (which are mostly offset by the same amount of operating revenues) and other factors.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and increases in intangible assets and changes in depreciation and amortization rates. See "Liquidity and Capital Resources" below for information regarding the planned additions to our facilities.
Pension and Other Postretirement Non-Service Credits, Net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them, as necessary. See Note 9.
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. Property tax increased in 2025 due to higher plant balances related to expansion and improvements on our existing generation, transmission, and distribution facilities, partially offset by legislative changes reducing both tax assessment ratios and rates in Arizona.
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 Notes 6 and 7 for further details. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. 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 - 2025 compared with 2024
Our consolidated net income attributable to common shareholders for the year ended
December 31, 2025 was $617 million, compared with consolidated net income attributable to common shareholders of $609 million for the prior-year period. The results reflect an increase of approximately $8 million, primarily as a result of increased customer usage, customer growth and related pricing, higher transmission revenues, impacts of new customer rates, higher LFCR revenue, and higher AFUDC. These positive factors were partially offset by the effects of weather, due primarily to extreme heat during the summer of 2024, the hottest on record in APS's service territory. Additional offsets include higher interest charges, lower pension and other postretirement non-service credits, higher depreciation and amortization expenses mostly due to increased plant additions and intangible assets, partially offset by operations ceasing at the Cholla plant and higher operations and maintenance expenses.
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 | ||||||||||||||||||||||||||||||||||
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||
| 2025 | 2024 |
Net Change |
2025 | 2024 |
Net Change |
||||||||||||||||||||||||||||||
| Operating revenues | $ | 5,340 | $ | 5,125 | $ | 215 | $ | 5,340 | $ | 5,125 | $ | 215 | |||||||||||||||||||||||
| Fuel and purchased power | (1,933) | (1,823) | (110) | (1,933) | (1,823) | (110) | |||||||||||||||||||||||||||||
| Operating revenues less fuel and purchased power (a) | 3,407 | 3,302 | 105 | 3,407 | 3,302 | 105 | |||||||||||||||||||||||||||||
| Operations and maintenance | (1,185) | (1,165) | (20) | (1,177) | (1,159) | (18) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (915) | (895) | (20) | (915) | (895) | (20) | |||||||||||||||||||||||||||||
| Taxes other than income taxes | (235) | (227) | (8) | (235) | (227) | (8) | |||||||||||||||||||||||||||||
| Allowance for equity funds used during construction | 61 | 39 | 22 | 61 | 39 | 22 | |||||||||||||||||||||||||||||
| Pension and other postretirement non-service credits, net | 12 | 49 | (37) | 13 | 49 | (36) | |||||||||||||||||||||||||||||
| Other income and (expense), net | 16 | 11 | 5 | (14) | (11) | (3) | |||||||||||||||||||||||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (422) | (377) | (45) | (332) | (312) | (20) | |||||||||||||||||||||||||||||
| Income taxes | (107) | (111) | 4 | (126) | (127) | 1 | |||||||||||||||||||||||||||||
| Less: Net income related to noncontrolling interests | (15) | (17) | 2 | (15) | (17) | 2 | |||||||||||||||||||||||||||||
|
Net Income Attributable to Common Shareholders
|
$ | 617 | $ | 609 | $ | 8 | $ | 667 | $ | 642 | $ | 25 | |||||||||||||||||||||||
(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 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 $105 million higher for the year ended December 31, 2025 compared with the prior-year period. The following table summarizes the major components of this change (dollars in millions):
| Increase (Decrease) | |||||||||||||||||
|
Operating revenues |
Fuel and purchased power |
Net change | |||||||||||||||
| Higher retail revenues due to changes in usage patterns, customer growth and related pricing, partially offset by the impacts of energy efficiency | $ | 155 | $ | 60 | $ | 95 | |||||||||||
|
Higher transmission revenues (Note 8)
|
51 | - | 51 | ||||||||||||||
|
Impact of new rates from the 2022 Rate Case, effective March 8, 2024 (Note 8)
|
46 | - | 46 | ||||||||||||||
|
LFCR revenue (Note 8)
|
10 | - | 10 | ||||||||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | 97 | 89 | 8 | ||||||||||||||
| Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs | 9 | 5 | 4 | ||||||||||||||
| Effects of weather | (157) | (43) | (114) | ||||||||||||||
| Miscellaneous items, net | 4 | (1) | 5 | ||||||||||||||
| Total | $ | 215 | $ | 110 | $ | 105 | |||||||||||
Operations and maintenance. Operations and maintenance expenses increased $20 million for the year ended December 31, 2025 compared with the prior-year period, primarily due to:
|
•an increase of $19 million related to information technology costs;
|
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•an increase of $16 million related to corporate resource costs;
|
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•an increase of $2 million related to nuclear generation costs;
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•an increase of $2 million related to costs for renewable energy programs and similar regulatory programs, which are partially offset in operating revenues and purchased power;
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•an increase of $1 million related to non-nuclear generation costs, primarily due to increased operating costs;
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•a decrease of $11 million related to transmission, distribution, and customer service costs;
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•a decrease of $13 million related to employee benefit costs; and
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•an increase of $4 million for other miscellaneous factors.
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Depreciation and amortization.Depreciation and amortization expenses were $20 million higher for the year ended December 31, 2025 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.
Pension and other postretirement non-service credits, net.Pension and other postretirement non-service credits, net were $37 million lower for the year ended December 31, 2025 compared to the prior-year period primarily due to prior-service credits becoming fully amortized as of January 31, 2025.
Other income and expense, net.Other income and expense, net was $5 million higher for the year ended December 31, 2025 compared to the prior-year period, primarily due to investment gains in El Dorado, partially offset by the gain on the sale of BCE recognized during the first quarter of 2024, lower PSA interest income and higher corporate giving expense. The difference between APS's and Pinnacle West's other income and expense, net is primarily related to Pinnacle West's gain in investment in El Dorado and the gain on the sale of BCE.
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 $23 million higher for the year ended December 31, 2025 compared to the prior-year period, primarily due to higher debt balances and lower allowance for borrowed funds, partially offset by higher allowance for equity funds.
Income taxes.Income taxes were $4 million lower for the year ended December 31, 2025 compared with the prior-year period, primarily due to higher tax benefits related to employee benefits and AFUDC Equity, offset by lower tax credits and higher pre-tax income.
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 December 31, 2025, APS's common equity ratio, as defined, was 52%. APS's total shareholder equity was approximately $8.9 billion, and total capitalization, as calculated pursuant to the ACC order, was approximately $17.1 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $6.8 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 May 15, 2025, Pinnacle West contributed $300 million into APS in the form of an equity infusion. APS used this contribution to repay the $300 million of its 3.15% senior notes that matured on the same date. On December 18, 2025, Pinnacle West contributed $75 million into APS in the form of an equity infusion. APS used this contribution to repay a portion of its commercial paper borrowings.
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. Approximately $700 million of common stock is available to be issued under the ATM Program, which takes into account the forward sale agreements in effect as of December 31, 2025. Pinnacle West also has forward sale agreements from an equity offering in February 2024 in effect as of December 31, 2025. See "Financing Cash Flows and Liquidity-Equity Offerings" below and Note 16 for more information.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2025, and 2024 (dollars in millions):
Pinnacle West Consolidated
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Net Change | |||||||||||||||
|
Net cash flow provided by operating activities
|
$ | 1,805 | $ | 1,610 | $ | 195 | |||||||||||
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Net cash flow used for investing activities
|
(2,378) | (1,934) | (444) | ||||||||||||||
|
Net cash flow provided by financing activities
|
576 | 323 | 253 | ||||||||||||||
|
Net increase (decrease) in cash and cash equivalents
|
$ | 3 | $ | (1) | $ | 4 | |||||||||||
APS Consolidated
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Net Change | |||||||||||||||
|
Net cash flow provided by operating activities
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$ | 1,827 | $ | 1,610 | $ | 217 | |||||||||||
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Net cash flow used for investing activities
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(2,370) | (1,986) | (384) | ||||||||||||||
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Net cash flow provided by financing activities
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543 | 375 | 168 | ||||||||||||||
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Net increase (decrease) in cash and cash equivalents
|
$ | - | $ | (1) | $ | 1 | |||||||||||
Operating Cash Flows
2025 Compared with 2024. Pinnacle West's consolidated net cash provided by operating activities was $1,805 million in 2025 compared to $1,610 million in 2024, an increase of $195 million in net cash provided, primarily due to $238 million higher cash receipts from electric revenues, $111 million in lower income taxes paid and $60 million lower payments for operations and maintenance costs; partially offset by $162 million higher payments for fuel and purchased power costs, $29 million in higher interest paid on debt and $23 million of changes in working capital. The difference between APS's and Pinnacle West's net cash provided by operating activities primarily relates to APS's lower payments for other taxes and other changes in working capital.
Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 ("ERISA") require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. The expected minimum required cash contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary cash contributions in 2026, 2027 or 2028; however, we continue to evaluate and assess our ongoing contribution strategy. Regarding contributions to our other postretirement benefit plan, we did not make a contribution in 2025 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
2025 Compared with 2024. Pinnacle West's consolidated net cash used for investing activities was $2,378 million in 2025 compared to $1,934 million in 2024, an increase of $444 million primarily related to $380 million of increased capital expenditures, net of contributions in aid of construction, and $84 million of proceeds from the BCE Sale received in 2024; partially offset by $20 million less investing activity in the current year. See "Capital Expenditures" below for additional details. The difference between APS's and Pinnacle West's net cash used for investing activities primarily relates to the proceeds received from the BCE Sale and investments made into the Captive Insurance Cell VIE in the prior year.
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 table above does not include capital expenditures related to PNW Power projects.
Generation capital expenditures are comprised of various additions and improvements to APS's 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 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
2025 Compared with 2024. Pinnacle West's consolidated net cash provided by financing activities was $576 million in 2025 compared to $323 million in 2024, an increase of $253 million in net cash provided primarily due to an increase of $430 million higher issuances of long-term debt, a $230 million increase in short-term borrowings and $75 million lower repayment of long-term debt; partially offset by $257 million less for equity issuances, the $199 million payment for the Palo Verde sale leaseback noncontrolling interest acquisition and higher dividends paid of $28 million.
APS's consolidated net cash provided by financing activities was $543 million in 2025 compared to $375 million in 2024, an increase of $168 million in net cash provided primarily due to an increase of $502 million higher issuances of long-term debt, a $360 million increase in short-term borrowings; partially offset by $420 million in lower equity infusions from Pinnacle West, the $199 million payment
for the Palo Verde sale leaseback noncontrolling interest acquisition, $50 million higher long-term debt repayments and $28 million in higher dividends paid to Pinnacle West.
Significant Financing Activities.On December 10, 2025, the Pinnacle West Board of Directors declared a dividend of $0.91 per share of common stock, payable on March 2, 2026, to shareholders of record on February 2, 2026. During 2025, Pinnacle West increased its indicated annual dividend from $3.58 per share to $3.64 per share. For the year ended December 31, 2025, Pinnacle West's total dividends paid per share of common stock were $3.60 per share, which resulted in dividend payments of $423 million.
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.
Equity Offerings.Pinnacle West entered into certain equity forward sale agreements in February 2024 and has an ATM Program under which Pinnacle West may offer and sell Pinnacle West common stock and enter into equity forward sale agreements from time to time, subject to market conditions and other factors. See Note 16. The following table summarizes the activity relating to these forward sale agreements and the ATM Program as of December 31, 2025 (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 | 2,199,415 | $ | 90.1038 | (a) (d) | $ | 198,176 | |||||||||||||||||
(a) Subject to certain adjustments.
(b) Physical delivery.
(c) Proceeds recorded in common equity on the Consolidated Balance Sheets.
(d) Weighted-average price for the total ATM Program.
Other Financing Matters.See Note 13 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 December 31, 2025, the ratio was approximately 60% for Pinnacle West and 50% for APS. Failure to comply with such covenant levels would result in an event
of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could "cross-default" other debt. See further discussion of "cross-default" provisions below.
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.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 20, 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 has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows:
•Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2055 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2025. See Note 7.
•Pinnacle West and APS maintain committed revolving credit facilities. See Note 6 for short-term debt details.
•Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 8 and 14. Purchase obligations may include commitments for capital expenditures and other obligations. See Note 14. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 20.
•APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 8 and 14.
•APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 12.
•APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation. See Note 14.
•Pinnacle West's equity forward sale agreements, which may be settled by Pinnacle West with common stock or cash. Pinnacle West has classified these agreements as equity transactions in accordance with GAAP. See Note 16.
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. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to other comprehensive income and result in lower future earnings. Management judgments also include assessing the impact of potential ACC- or FERC-ordered refunds to customers on regulatory liabilities. We had $1,749 million of regulatory assets and $1,947 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2025. See Notes 1 and 8 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position. We review these assumptions on an annual basis and adjust them as necessary. The most relevant actuarial assumptions are the discount rate, the expected long-term rate of return on plan assets ("EROA"), and the assumed healthcare cost trend rates. Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense. To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years. Following are the most relevant actuarial assumptions:
Discount Rate.The discount rate is used to measure the plan liability and net periodic cost. For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future benefit payments to estimate the projected benefit obligation for each plan. This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year's benefit payments by a spot rate to that year. The spot rates are derived from a yield curve composed of domestic AA rated corporate bonds.
EROA. The EROA is used to estimate earnings on invested funds over the long-term. For this assumption, we consider historical experience and future expectations of asset classes utilized in the portfolio.
Healthcare Cost Trend Rates.We consider past performance and forecasts of health care costs, and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2025, reported pension assets and liabilities on the Consolidated Balance Sheets and our 2025 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions):
| Increase (Decrease) | ||||||||||||||
| Actuarial Assumption (a) |
Impact on Pension Plans (Assets) Liabilities |
Impact on Pension Expense (Benefit) |
||||||||||||
| Discount rate (b): | ||||||||||||||
| Increase 1% | $ | (236) | $ | (8) | ||||||||||
| Decrease 1% | 279 | 8 | ||||||||||||
| EROA: | ||||||||||||||
| Increase 1% | - | (19) | ||||||||||||
| Decrease 1% | - | 19 | ||||||||||||
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the obligation and expense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2025 other postretirement benefit obligation on the Pinnacle West's Consolidated Balance Sheets and our 2025 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West's Consolidated Statements of Income (dollars in millions):
| Increase (Decrease) | ||||||||||||||
| Actuarial Assumption (a) |
Impact on Other Postretirement Benefit Plans (Assets) Liabilities |
Impact on Other Postretirement Benefit Expense (Benefit) |
||||||||||||
| Discount rate (b): | ||||||||||||||
| Increase 1% | $ | (33) | $ | (1) | ||||||||||
| Decrease 1% | 40 | 2 | ||||||||||||
| Healthcare cost trend rate (c): | ||||||||||||||
| Increase 1% | 13 | 2 | ||||||||||||
| Decrease 1% | (11) | (1) | ||||||||||||
| EROA - pretax: | ||||||||||||||
| Increase 1% | - | (5) | ||||||||||||
| Decrease 1% | - | 5 | ||||||||||||
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated.
(c)This assumes a 1% change in the initial and ultimate healthcare cost trend rate.
See Note 9 for further details about our pension and other postretirement benefit plans.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trusts fund, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion of accounting policies and Note 17 for fair value measurement disclosures.
Asset Retirement Obligations
We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the asset's current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.
AROs as of December 31, 2025 are described further in Note 21.
OTHER ACCOUNTING MATTERS
See Note 3 for information relating to the following new accounting standards:
•ASU 2023-09, Income Taxes: Improvements to Income Tax Disclosures, adopted on December 31, 2025. See Note 5.
•ASU 2024-03, Income Statement Reporting: Expense Disaggregation Disclosures, effective for us on December 31, 2027, with early adoption permitted.
•ASU 2025-03, Business Combinations and Consolidation: Determining the Accounting Acquirer in the Acquisition of a VIE, effective for us on January 1, 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.
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 17 and 18), 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.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2025 and 2024. If variable interest rates were to increase by 10% from the December 31, 2025, levels, it would not have a material effect on Pinnacle West Consolidated or APS Consolidated annual interest expense. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2025 and 2024 (dollars in millions):
Pinnacle West Consolidated
|
Short-Term Debt |
Variable-Rate Long-Term Debt |
Fixed-Rate Long-Term Debt |
||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2025 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2026 | 3.98 | % | $ | 757 | 5.10 | % | $ | 350 | 2.55 | % | $ | 250 | ||||||||||||||||||||||||||
| 2027 | - | - | - | - | 4.10 | % | 825 | |||||||||||||||||||||||||||||||
| 2028 | - | - | - | - | 4.90 | % | 400 | |||||||||||||||||||||||||||||||
| 2029 | - | - | 3.52 | % | 164 | 2.60 | % | 405 | ||||||||||||||||||||||||||||||
| 2030 | - | - | - | - | 5.15 | % | 400 | |||||||||||||||||||||||||||||||
| Years thereafter | - | - | - | - | 4.62 | % | 7,075 | |||||||||||||||||||||||||||||||
| Total | $ | 757 | $ | 514 | $ | 9,355 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 757 | $ | 514 | $ | 8,651 | ||||||||||||||||||||||||||||||||
|
Short-Term Debt |
Variable-Rate Long-Term Debt |
Fixed-Rate Long-Term Debt |
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| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2024 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2025 | 4.90 | % | $ | 568 | - | $ | - | 1.99 | % | $ | 800 | |||||||||||||||||||||||||||
| 2026 | - | - | 5.88 | % | 350 | 2.55 | % | 250 | ||||||||||||||||||||||||||||||
| 2027 | - | - | - | - | 4.10 | % | 825 | |||||||||||||||||||||||||||||||
| 2028 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||
| 2029 | - | - | 4.01 | % | 164 | 2.60 | % | 405 | ||||||||||||||||||||||||||||||
| Years thereafter | - | - | - | 4.31 | % | 6,125 | ||||||||||||||||||||||||||||||||
| Total | $ | 568 | $ | 514 | $ | 8,405 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 568 | $ | 514 | $ | 7,405 | ||||||||||||||||||||||||||||||||
The tables below present contractual balances of APS's long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2025, and 2024. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2025, and 2024 (dollars in millions):
APS Consolidated
|
Short-Term Debt |
Variable-Rate Long-Term Debt |
Fixed-Rate Long-Term Debt |
||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2025 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2026 | 3.83 | % | $ | 507 | - | $ | - | 2.55 | % | $ | 250 | |||||||||||||||||||||||||||
| 2027 | - | - | - | - | 2.95 | % | 300 | |||||||||||||||||||||||||||||||
| 2028 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||
| 2029 | - | - | 3.52 | % | 164 | 2.60 | % | 405 | ||||||||||||||||||||||||||||||
| 2030 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||
| Years thereafter | - | - | - | - | 4.62 | % | 7,075 | |||||||||||||||||||||||||||||||
| Total | $ | 507 | $ | 164 | $ | 8,030 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 507 | $ | 164 | $ | 7,269 | ||||||||||||||||||||||||||||||||
|
Short-Term Debt |
Variable-Rate Long-Term Debt |
Fixed-Rate Long-Term Debt |
||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2024 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2025 | 4.62 | % | $ | 340 | - | $ | - | 3.15 | % | $ | 300 | |||||||||||||||||||||||||||
| 2026 | - | - | - | - | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| 2027 | - | - | - | - | 2.95 | % | 300 | |||||||||||||||||||||||||||||||
| 2028 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||
| 2029 | - | - | 4.01 | % | 164 | 2.60 | % | 405 | ||||||||||||||||||||||||||||||
| Years thereafter | - | - | - | - | 4.31 | % | 6,125 | |||||||||||||||||||||||||||||||
| Total | $ | 340 | $ | 164 | $ | 7,380 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 340 | $ | 164 | $ | 6,361 | ||||||||||||||||||||||||||||||||
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions):
| December 31, 2025 | December 31, 2024 | ||||||||||
| Mark-to-market of net positions at beginning of year | $ | (42) | $ | (120) | |||||||
| Decrease in regulatory asset | 16 | 78 | |||||||||
| Mark-to-market of net positions at end of year | $ | (26) | $ | (42) | |||||||
The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 2025, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, "Derivative Accounting" and "Fair Value Measurements," 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 | $ | (6) | $ | 6 | $ | (2) | $ | - | $ | - | $ | (2) | |||||||||||||||||||||||||||||
| Prices based on unobservable inputs | (24) | - | - | - | - | (24) | |||||||||||||||||||||||||||||||||||
| Total by maturity | $ | (30) | $ | 6 | $ | (2) | $ | - | $ | - | $ | (26) | |||||||||||||||||||||||||||||
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 Consolidated Balance Sheets (dollars in millions):
|
December 31, 2025
Gain (Loss)
|
December 31, 2024
Gain (Loss)
|
||||||||||||||||||||||
| Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||||||||||
| Mark-to-market changes reported in: | |||||||||||||||||||||||
| Regulatory asset (liability) (a) | |||||||||||||||||||||||
| Electricity | $ | 3 | $ | (3) | $ | 3 | $ | (3) | |||||||||||||||
| Natural gas | 58 | (58) | 75 | (75) | |||||||||||||||||||
| Total | $ | 61 | $ | (61) | $ | 78 | $ | (78) | |||||||||||||||
(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 13 for a discussion of our credit valuation adjustment policy.
Pinnacle West Capital Corporation published this content on February 25, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on February 25, 2026 at 13:27 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]