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Item 7. Management’s Discussion and Analysis

2026-02-25 compared with 2025-02-25 · 317 added, 391 removed, 424 unchanged (63% of the section changed)

8 unchanged sentences

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $30 billion.

Since 1886, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS.

APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.4 million retail customers in 11 of Arizona’s 15 counties.

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 strategy is to create a sustainable energy future for Arizona that delivers shareholder value and shared value by serving our customers with reliable, affordable, and clean energy.

Customer-Focused

APS’s focus remains on its customers and the communities it serves.

Accordingly, it is APS’s goal to achieve an industry-leading, best-in-class customer experience.

This multi-year objective includes incrementally improving APS’s J.D.

Power (“JDP”) residential and business customer satisfaction ratings from the fourth to the top of second quartile for its customers.

For 2024, APS ranked at the top of the second quartile for large investor-owned utilities for both business and residential customers, with the residential results being APS’s highest rank and placement since 2016.

In furtherance of a customer-centric culture, APS employees have delivered an enhanced customer experience in recent years through a number of past and ongoing initiatives, such as improving the ease-of-use of APS’s automated phone system, improving the speed of answering customer calls, advancing phone advisor soft skill development through updated training curriculum, and adding 1,100-plus in-person payment locations, as well as introducing new customer payment channels.

Recently, APS redesigned its customer bills with the aim of increasing personalization and helping customers better understand their

energy use and find ways to save.

APS also implemented numerous enhancements to its website, including improving page-loading speeds, adding user-friendly dashboards, and making content more simple, relevant, and useful.

APS enhanced other customer touchpoints, such as communications throughout outages and the online outage center in addition to continuing to communicate with customers in their preferred channels about topics that matter most to them, such as reliability, energy-efficiency, financial assistance, the environment, and programs that enable them to design their own personalized energy experience.

Finally, APS continues to focus on employee learning, training, tools, and resources to ensure all employees understand their role in APS customers’ experiences.

Additionally, APS has implemented a variety of financial assistance programs to support customers struggling to pay their energy bills.

Among these assistance programs are discounts for qualified limited-income customers, including a new tier with larger discounts for APS’s lowest income customers added in the second quarter of 2024 and other non-income-based assistance programs, such as flexible payment arrangements and emergency utility bill assistance.

To ensure our most vulnerable customers are connected to these programs, we train and partner with more than one hundred community action agencies across our service territory.

While our energy mix evolves, APS’s commitment to deliver reliable service to our customers remains.

APS is managing through significant growth in the Phoenix metropolitan area while experiencing supply chain issues similar to those experienced in other industries.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth, and enabling more renewable energy resources.

To prioritize reliability and meet substantial growth in customer energy needs, APS has developed a future-focused, strategic transmission plan (the “Ten-Year Transmission Plan”).

The Ten-Year Transmission Plan includes five critical transmission projects that comprise the APS strategic transmission portfolio, which represent a significant upgrade to our transmission system.

These five projects, along with other projects included in the Ten-Year Transmission Plan, will support growing energy needs, strengthen reliability, and allow for the connection of new resources.

Our advanced distribution management system allows operators to locate outages and control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid.

The system will also integrate a new meter data management system that will increase grid visibility and give customers access to more of their energy usage data.

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.

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.

We have increased investment in fire mitigation efforts to clear defensible space around our infrastructure, continue ongoing system upgrades, build partnerships with government entities and first responders and educate customers and communities.

We 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.

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 recent wildfire events in Hawaii, California, and across North America, we have been devoting and will continue to devote substantial efforts to analyzing and developing enhancements to our systems and processes to mitigate fire risk within our 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 completed implementation of fire modelling software that we are utilizing to more surgically 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.

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 PSPS program on certain feeders that began in the 2024 fire season, leveraging the additional real-time analysis provided by the new modelling software, and has educated and is continuing education outreach to customers and communities that may potentially be impacted by the PSPS program.

APS continues to evaluate policy and regulatory options, as well as insurance programs, to mitigate the impact of wildfire events.

For example, on August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs.

APS cannot predict the outcome of this matter.

See Note 3 for more information.

Additionally, APS was selected by the DOE’s Grid Deployment Office (“GDO”) to receive up to $70 million in federal money for fire mitigation and grid infrastructure projects.

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.

Maintaining reliability and affordability for customers during the clean energy transition is fundamental to APS’s strategy.

Dispatchable natural gas generators provide energy during times when intermittent resources, such as solar and wind, are insufficient to meet customer demand.

In addition to the previously added natural gas units at the modernized Ocotillo Power Plant in 2019 and efficiency improvements to gas units at the Redhawk, Sundance, and West Phoenix Power Plants in 2024, APS has contracted for two simple cycle combustion turbines (approximately 90 MW in total) at Sundance, which are expected to be in service in 2026, and eight simple cycle combustion turbines (approximately 397 MW in total) at Redhawk, which are expected to be in service in 2028.

APS continues to evaluate and pursue options for reliably serving growing customer energy needs and demand.

In October 2021, APS announced plans to evaluate regional market solutions as part of the Western Markets Exploratory Group (“WMEG”).

As a member of WMEG, APS explored the potential for a staged approach to new market services, including day-ahead energy sales, transmission system expansion, and other power supply and grid solutions consistent with existing regulations and known and expected market design.

APS utilizes the work done by WMEG to help identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers.

APS went live with a new Energy Management System (“EMS”) in April 2024.

APS expects the new EMS to provide a better foundation which will improve future integration of the renewable and energy storage assets into APS’s generation resource portfolio, allowing APS to maximize the flexibility of its resources and fully engage in the Western Energy Imbalance Market (“WEIM”).

APS also believes it will better position APS to participate in market opportunities that develop over the next decade.

APS’s key elements to delivering reliable power include resource and transmission planning, sufficient reserve margins, partnering with customers to manage peak demand, fire mitigation, and operational preparedness, among others.

Seasonal readiness procedures at APS include inspections to ensure good material conditions and critical control system surveys.

APS also plans for the unexpected by conducting emergency operations drills and coordinating with federal, state, and local agencies on fire and emergency management.

APS continues to focus on mitigating the cost pressures related to inflation and other factors, such as tariffs.

Overall inflation grew by 1.6% in Phoenix and 2.9% nationally over the twelve months ended December 2024.

Although inflationary impacts to APS began to slow in 2024, APS is still managing the impacts high inflation.

Additionally, the implementation of recent and future tariffs could further escalate costs and introduce supply chain constraints.

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.

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 an 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 areas such as transformers;

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.

There are also external opportunities under APS’s customer affordability initiative, such as APS’s participation in the WEIM.

WEIM continues to be a tool for creating savings for APS’s customers from the real-time, voluntary market.

APS continues to expect that its participation in WEIM will lower its fuel and purchased-power costs, improve situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.

APS participated in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool (“SPP”).

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 announced a market decision to pursue participation in SPP Markets+.

In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool and is transitioning to full binding participation as early as summer 2027.

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.

In terms of generation affordability, every three years, APS performs a comprehensive study, called an Integrated Resource Plan (“IRP”), to identify what resources will be necessary to safely and reliably meet the demand and energy needs of its customers over the next 15 years.

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 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 in the most affordable and sustainable manner possible.

To help ensure competitive costs for resources procured by APS, APS regularly issues competitive bid solicitations through the ASRFP process, with the most recent ASRFPs being issued in 2022, 2023, and 2024.

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.

Through the ASRFP process, APS has found that clean resources like wind, solar, and energy storage technology, are important elements of a least cost portfolio.

During the clean energy transition, dispatchable resources will play a vital role in maintaining grid reliability by serving as a back-up to intermittent energy resources when output is insufficient to meet customer needs.

Over the long term, each resource in a balanced and diverse portfolio is expected to provide complementary value and contribute to sustained delivery of reliable electric service.

In addition to managing the cost of electricity generation, APS has continued building upon existing cost management efforts, including a customer affordability initiative launched in 2019.

The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes

and organizational approaches to completing high-value work and achieving internal efficiencies.

APS continues to drive this initiative by identifying opportunities to streamline its business processes, mitigate cost increases, increase employee retention, and improve customer satisfaction.

Clean Energy Commitment

We are committed to doing our part to build a clean and carbon-free future.

As Arizona stewards, we do what is right for the people and prosperity of Arizona.

Our vision is to create a sustainable energy future for Arizona by providing reliable, affordable, and clean energy to our customers.

We can accomplish our vision by collaborating with customers, communities, employees, policymakers, shareholders, and other stakeholders.

Our clean energy commitment is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

APS’s clean energy commitment consists of three parts:

• A 2050 goal to provide 100% clean, carbon-free electricity;

• A 2030 target to achieve a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy;

• A plan to exit from coal-fired generation by 2031.

APS’s ability to successfully execute its clean energy commitment depends upon a number of important external factors, including a supportive regulatory environment, sales and customer growth, development of clean energy technologies, and continued access to capital markets, among others.

100% Clean, Carbon-Free Electricity.

Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration.

Achieving this 2050 goal will require, among other things, innovative thinking, emergent clean energy and storage technologies, upgrades and expansions to the grid, and supportive public policy.

65% Clean Energy.

APS has an energy mix that is already more than 50% clean and plans to continue to add more renewables and energy storage.

By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy.

“Clean” is measured as percent of energy mix, which includes all carbon-free resources like nuclear, renewables, and demand-side management.

“Renewable” energy includes generation resources such as solar, wind, and biomass, and is measured in accordance with the ACC Renewable Energy Standard as a percentage of retail sales.

This target will serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward a 100% clean, carbon-free energy mix by 2050.

Exit Coal-Fired Generation.

The plan to exit coal-fired generation by 2031 will require APS to stop relying on coal-generation at Four Corners.

APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity.

These closures and other measures taken by APS have resulted in annual carbon emissions that were 36% lower in 2023 compared to 2005.

In addition, APS has committed to end the use of coal at its remaining Cholla units during 2025.

In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners as early as fall 2023, subject to the

necessary governmental approvals and conditions associated with changes in plant ownership.

Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring.

The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages.

As of the date of this report, APS has elected not to begin seasonal operation due to market conditions.

APS’s IRP identifies a diverse mix of resources adequate to maintain grid reliability while serving increasing future customer energy needs.

Our IRP shows that renewable and clean resources are an important part of a reliable, cost effective portfolio.

APS seeks market-based pricing of procured resources through regular solicitation of project bids using its competitive ASRFP process.

APS has a diverse portfolio of existing and planned resources, including solar, wind, energy storage, nuclear, geothermal, biomass and biogas, that supports our commitment to clean energy.

This commitment is already strengthened by Palo Verde, one of the nation’s largest carbon-free, clean energy resources, which provides the foundation for reliable and affordable service for APS customers.

APS’s longer-term clean energy strategy includes pursuing the right mix of purchased power contracts for new resources, procurement of new resources to be owned by APS, and the ongoing development of distributed energy resources.

Maintaining a balanced and diverse portfolio of resources will ensure continued reliable service to our customers in the most affordable manner possible.

APS uses competitive ASRFPs to pursue market-priced resources that meet its system needs and offer the best value for customers.

APS selects projects based on cost, ability to meet system requirements and commercial viability, taking into consideration timing and likelihood of successful contracting and development.

Under current market conditions, APS must aggressively contract for resources that can withstand supply chain and other geopolitical pressures.

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.

On June 30, 2023, APS issued an ASRFP (the “2023 ASRFP”) pursuant to which APS procured nearly 7,300 MW of new resources to be in service from 2026 to 2028.

On November 20, 2024, APS issued an ASRFP (the “2024 ASRFP”) seeking 2,000 MW of resources.

APS is seeking projects that can reach commercial operation beginning June 1, 2028 through June 1, 2030 but will consider projects that may achieve commercial operation as early as 2026.

Additionally, APS is interested in projects that require longer planning, permitting, and construction and can be commercially operational after June 1, 2030.

Bids for the 2024 ASRFP were due on February 5, 2025.

The following table summarizes the resources in APS’s renewable energy portfolio that are in operation, planned or under development as of the date of this report.

Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting, and interconnection of the projects to the electric grid.

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

Total APS Owned:

Solar 416 168

PPAs Renewables:

Solar 585 3,321

Geothermal 10 —

Total PPAs 1,465 3,821

Total Distributed Energy:

Solar (a) 1,727 63 (b)

Total Renewable Portfolio 3,608 4,052

(a) Includes rooftop solar facilities owned by third parties.

DG is produced in direct current and is converted to alternating current for reporting purposes.

(b) Applications received by APS that are not yet installed and online.

Energy Storage.

APS deploys a number of advanced technologies on its system, including energy storage.

Energy storage provides capacity, improves power quality, can be utilized for system regulation and, in certain circumstances, be used to defer certain traditional infrastructure investments.

Energy storage also aids in integrating renewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset.

APS is utilizing grid-scale energy storage projects to meet customer reliability requirements, increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation, planned or under development as of the date of this report.

Agreements for the development and completion of future resources are subject to various conditions.

Net Capacity in Operation (MW) Net Capacity Planned / Under Development (MW)

APS Owned Energy Storage 201 (a) 150

PPAs Energy Storage 405 5,087

Customer-Sited Energy Storage 62 51

Total Energy Storage Portfolio 668 5,288

(a) Includes 0.3 MW of APS-owned customer-sited energy storage.

Palo Verde, one of the nation’s largest carbon-free, clean energy resources, will continue to be a foundational part of APS’s resource portfolio.

Palo Verde is not just the cornerstone of our current clean energy mix;

it also is a significant provider of clean energy to the southwestern United States.

The plant is a critical asset to the Southwest, generating more than 32 million MWh annually –

enough power for roughly 3.4 million households, or approximately 8.5 million people.

Its continued operation is important to a carbon-free and clean energy future for Arizona and the region, a s a reliable, continuous, affordable resource and as a large contributor to the local economy.

Developing Clean Energy Technologies

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 .

APS, along with other Arizona electric utilities, is exploring new nuclear generation to provide around-the-clock carbon-free energy to meet rising energy demands in Arizona.

APS has been monitoring emerging nuclear technologies, such as small modular nuclear reactors (“SMRs”).

SMRs 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 the DOE to begin preliminary exploration of a potential site for additional nuclear energy for Arizona.

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.

Electric Vehicles

As a part of the statewide transportation electrification plan (“TE Plan”) adopted in 2021, the ACC approved a target of 450,000 light-duty electric vehicles (“EVs”) in APS’s service territory by 2030.

APS’s Take Charge AZ (“TCAZ”) program has helped to deploy Level 2 EV charging stations on customer properties for fleet, public, and workplace EV charging.

As of December 31, 2024, APS has installed 829 energized Level 2 charging ports at 197 customer locations.

Additionally, APS has energized direct current fast charging stations that are owned and operated by APS at five locations in Arizona:

Sedona, Prescott, Globe, Show Low, and Payson.

Effective December 12, 2023, the TCAZ program was discontinued by the ACC.

As part of that decision, APS was permitted to complete certain projects that were in process as of December 12, 2023.

Additionally, as part of APS’s DSM Implementation Plan, APS launched the EV Charging Demand Management Pilot to proactively address the growing electric demand from charging as EVs become more widely adopted.

The EV programs in the DSM Implementation Plan include APS SmartCharge (an EV data gathering program), Fleet Advisory Services, and a $100 rebate to home builders for new homes to be built EV-ready with 240V receptacle.

APS previously offered a $250 residential rebate to customers that purchased a qualifying home Level 2 charger.

Effective December 12, 2023, APS discontinued this rebate per the ACC decision.

See the discussion above.

APS filed its 2024 DSM Implementation Plan on November 30, 2023.

The 2024 DSM Implementation Plan includes APS’s 2024 TE Plan and, among other things, proposes two new programs that were initially proposed in the 2023 DSM Implementation Plan:

an expanded residential EV Managed Charging program and a Commercial EV Make-Ready Program.

On April 26, 2024, APS filed an amended 2024 DSM Implementation Plan.

The amended 2024 DSM Implementation Plan includes an updated budget of $90.9 million to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot.

The amended 2024 DSM Plan is still pending ACC review and approval.

APS will not file a 2025 DSM Implementation Plan, pending ACC review of the amended 2024 DSM Implementation Plan.

APS cannot predict the outcome of this proceeding.

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 .

Carbon Capture Utilization and Storage (“CCUS”) technologies can isolate CO 2 and either sequester it permanently in geologic formations or convert it for use in products.

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.

CCUS technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions.

These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired.

APS will continue to monitor this emerging technology.

Sustainability Practices

In 2020, in support of our clean energy commitment and the growing focus on sustainability within our organization, we increased our focus on sustainability by dedicating a new Sustainability Department at Pinnacle West responsible for integrating responsible business practices into the everyday work of the Company.

In 2024, the Sustainability Department engaged an external consultant and leveraged input from employees, large customers, limited-income advocates, economic development groups, tribes, nonprofits, environmental non-governmental organizations, residential customers, and other stakeholders to identify and assess the sustainability issues that matter most.

In total, 15 Priority Sustainability Issues (“PSIs”) were identified and prioritized.

The top five issues that were prioritized by stakeholders are as follows:

energy affordability, electric reliability, clean energy and decarbonization, workforce development, and climate resilience and adaptation.

Understanding the sustainability priorities of internal and external stakeholders can help companies improve performance, identify risks and opportunities, and refine sustainability strategy.

Finally, the Company maintains an annual Corporate Responsibility Report on the Pinnacle West website ( www.pinnaclewest.com/corporate-responsibility ).

The report provides information related to the Company’s sustainability practices and performance.

The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into or otherwise a part of this report.

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 artificial intelligence technology risks and opportunities, APS has developed a cross functional governance structure with leadership and experts from our information technology, cybersecurity, human resources, ethics, supply chain, legal, and nuclear generation teams.

This cross functional structure assesses the opportunities and risks in alignment with enterprise strategy to ensure compliance with data security and reliability requirements as well as our Code of Ethical Conduct, while observing market trends in this rapidly evolving area.

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

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

2022 Retail Rate Case

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

On January 25, 2024, an Administrative Law Judge issued a ROO in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

The 2022 Rate Case ROO recommended, among other things, (i) a $523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36%, (v) 12 months of post-test year plant and the inclusion of the Four Corners Effluent Limitations Guideline (“ELG”) project, (vi) the approval of APS’s System Reliability Benefit (“SRB”) proposal with certain procedural and other modifications, (vii) no additional Coal Community Transition (“CCT”) funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the OPEB liability, and (ix) no disallowances on APS’s coal contracts.

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

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

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill.

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:

Capital Structure

Cost of Capital

Long-term debt

47.65 % 4.26 %

Common stock equity

52.35 % 10.70 %

Weighted-average cost of capital

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

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

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

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

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

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

• 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 CCT funding.

On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association, Solar Energy Industries Association, and Vote Solar specifically to review whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers.

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.

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The Limited Rehearing ROO recommended affirming the GAC as just and reasonable and that the GAC is not discriminatory to solar customers and the absence of a GAC is not discriminatory to non-solar customers.

On December 17, 2024, the ACC approved the Limited Rehearing ROO with an amendment that requires

APS in its next rate case to propose a revenue allocation based on a site-load cost of service study in order to bring further parity in revenue collection between solar and non-solar customers.

SEIA, AriSEIA, Vote Solar, the Arizona Attorney General, and two individual customers have filed requests for rehearing of the Commission’s December 17, 2024 decision on the rehearing.

The Commission has taken no action on these requests.

In addition, each of these parties have subsequently filed notices of appeal to the Arizona Court of Appeals seeking review of the Commission’s decisions regarding the GAC and on rehearing.

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.

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) for an annual increase in retail base rates.

On August 2, 2021, an Administrative Law Judge issued a ROO in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

Subsequently, the ACC approved an amended 2019 Rate Case ROO on November 2, 2021.

After the 2019 Rate Case decision, APS filed an application for rehearing of the 2019 Rate Case and later filed a Notice of Direct Appeal by APS at the Arizona Court of Appeals, requesting review of certain matters from the 2019 Rate Case decision.

The Arizona Court of Appeals affirmed in part and reversed in part the ACC’s decision in the 2019 Rate Case, remanding the issue to the ACC for further proceedings.

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

The joint resolution provides for a new Court Resolution Surcharge (“CRS”) mechanism, which is designed to recover the $59.6 million in revenue lost by APS between December 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates.

On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the CRS mechanism, which became effective on July 1, 2023.

As of December 31, 2024, $26.2 million of the $59.6 million of lost revenue has been recovered.

Finally, the CRS tariff has been updated to account for changes to return on equity and depreciation and deferral adjustments approved in Decision No.

79293 in the 2022 Rate Case.

Regulatory Lag Docket

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On December 3, 2024, the ACC approved a policy statement regarding formula rate plans.

The policy statement allows regulated utilities to propose formula rate plans in future rate cases.

Proposed plans must be based on a historical test year, include an annual update with a true-up and an earnings test to ensure a utility earns within a 20 basis points band of its authorized return on equity.

Proposed plans should also include an annual meeting and challenge periods for stakeholder feedback.

Utilities that implement formula rates also must file a full rate case at least every five years unless an alternate schedule is set by the ACC.

APS cannot predict the outcome of this matter.

On August 14, 2024, APS filed a request with the ACC for a deferral order associated with unrecovered book value and closure costs of the remaining Cholla units.

This order would authorize APS to defer, for future recovery in rates, both the expenses necessary to close and decommission coal-fired power plant infrastructure at Cholla, including legally required site environmental remediation, CCR corrective actions, the closure of CCR management facilities, and any unrecovered plant investment and operating costs incurred through and after April 2025.

APS cannot predict the outcome of this matter.

Fire Mitigation

On August 14, 2024, APS filed a request with the ACC for a deferral order that would authorize APS to defer, for future recovery in rates, operations and maintenance expenses associated with wildfire management, including increased insurance costs.

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 3 for information regarding additional regulatory matters.

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 company.

The Captive provides insurance coverage to Pinnacle West and our subsidiaries that supplements third-party insurance policies.

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.

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The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments.

Inflation Reduction Act of 2022

The Inflation Reduction Act of 2022 (“IRA”) significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage.

Key provisions that are relevant to APS’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a Production Tax Credit ( “ PTC ” ) in lieu of the Investment Tax Credit ( “ ITC ” ) beginning in 2022;

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;

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and (iv) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032.

The Internal Revenue Service and U.S.

Treasury Department have issued preliminary guidance related to various provisions of the IRA that have enabled APS to claim credits related to its solar and energy storage investments.

The Company continues to await regulations and other guidance, including with respect to the nuclear PTC, which will provide additional details and clarifications regarding how the Company may be able to claim IRA tax credits.

See Note 4 for more information.

The prospects for federal tax reform, including potential modification or repeal of the IRA tax provisions, have increased due to the results of the 2024 election.

Any such reform may impact the availability of future potential tax benefits from the IRA and could impact the Company’s effective tax rate, cash taxes paid and other financial results such as earnings per share, gross revenues, and cash flows.

We cannot predict the timing or extent of such tax-related developments which, absent appropriate regulatory treatment, may have a negative impact on our financial results.

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

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 will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

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

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary BCE to Ameresco (the “BCE Sale”).

The transaction was accounted for as the sale of a business and closed in multiple stages.

T he final closing of the BCE Sale was completed on January 12, 2024.

See Note 20 for additional details.

Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to PNW Power, a wholly-owned subsidiary of Pinnacle West.

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.

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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 venture partners’ utility affiliates.

Department of Energy’s Grid Deployment Office selected TransCanyon to enter into capacity contract negotiations for up to 25% of the Cross-Tie 500-kilovolt transmission line (“Cross-Tie”) as part of the Transmission Facilitation Program.

The agreement was executed on June 12, 2024.

The proposed Cross-Tie project 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.

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.

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PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.

El Dorado is a wholly-owned subsidiary of Pinnacle West.

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 the following:

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 (formerly invisionAZ Fund), of which approximately $11.8 million has been funded as of December 31, 2024.

other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona.

• $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 Advanced Power Solutions (“SAI”), a private corporation that manufactures electrical switchgear equipment used by data centers.

El Dorado accounts for this investment under the equity method, with a December 31, 2024 investment carrying value of zero.

SAI has seen an increased demand for their customized switchgear products.

El Dorado has no funding commitments to SAI.

• 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.

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Electric Operating Revenues.

For the years 2022 through 2024, retail electric revenues comprised approximately 92% of our total 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.

These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand, and prices.

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 year ended December 31, 2024, compared with the prior-year period.

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 5.7% for the year ended December 31, 2024, compared with the prior-year period.

While steady customer growth was somewhat offset by weaker usage among residential customers, energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong sales to commercial and industrial customers and the ramp-up of new data center and large manufacturing customers.

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 large data centers and new 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 2025 and that average annual growth will be in the range of 4.0% to 6.0% through 2027, 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 large data centers and new large manufacturing facilities, which are expected to contribute to 2025 growth in the range of 3.0% to 5.0% and to average annual growth in the range of 3.0% to 5.0% through 2027.

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 now receiving unprecedented incremental requests for service from extra-large commercial energy users (over 25 MW) with very high energy demands that persist virtually around-the-clock.

These incremental requests for service by extra-large energy users far exceed available generation and transmission resource capacity in the Southwest region for the foreseeable future.

In April 2023, APS notified prospective extra-large customers without existing commitments from APS that it is not able to commit at this time to future extra-large projects of over 25 MW.

Because of the high growth in demand for such projects, APS has developed a prioritization queue that identifies and prioritizes projects while maintaining system reliability and affordability for existing APS customers.

APS is exploring available options for securing sufficient electric generation and transmission to meet these projections of future customer needs.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, slower ramp-up of and/or fewer data centers and large 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.

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.

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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 Costs.

Fuel and purchased power costs 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.

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 .

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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 taxes increased in 2024 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 property tax assessment ratios and rates in Arizona.

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, and non-taxable items, such as AFUDC.

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.

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Interest expense is affected by the amount of debt outstanding and the interest rates on that debt.

See Note 6 for further details.

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.

An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.

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 traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission, and distribution.

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.

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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 $107 million, primarily as a result of the impacts of new customer rates, increased customer usage and growth, the effects of weather, and higher CRS revenue and LFCR revenue.

These positive factors were partially offset by higher operations and maintenance expense, higher depreciation and amortization expense mostly due to increased plant and intangible assets, higher interest charges, net of AFUDC, higher income taxes and lower transmission revenues.

The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated:

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

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Change 2025 2024 Net

(dollars in millions)

Operating revenues $ 5,340 $ 5,125 $ 215 $ 5,340 $ 5,125 $ 215

Fuel and purchased power expense (1,823) (1,793) (30) (1,823) (1,793) (30)

Operating revenues less fuel and purchased power expenses 3,302 2,903 399 3,302 2,903 399

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)

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Pension and other postretirement non-service credits, net 12 49 (37) 13 49 (36)

Other income and expenses, net 11 7 4 (11) 7 (18)

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 income related to noncontrolling interests (17) (17) — (17) (17) —

Net income related to noncontrolling interests (15) (17) 2 (15) (17) 2

Net Income Attributable to Common Shareholders

$ 617 $ 609 $ 8 $ 667 $ 642 $ 25

Operating revenues less fuel and purchased power expenses.

(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:

The following table summarizes the major components of this change (dollars in millions):

Increase (Decrease)

revenues Fuel and

power expenses Net change

(dollars in millions)

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)

Impact of new rates from the 2022 Rate Case, effective March 8, 2024 (Note 8)

$ 260 $ — $ 260

Higher retail revenue due to changes in usage patterns and customer growth partially offset by the impacts of energy efficiency and related pricing 112 55 57

Effects of weather 76 23 53

CRS revenue (Note 3)

Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs 21 4 17

LFCR revenue (Note 8)

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 97 89 8

Lower transmission revenues (Note 3)

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

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• an increase of $19 million related to information technology costs;

• an increase of $25 million related to transmission, distribution, and customer service costs;

• an increase of $20 million related to non-nuclear generation costs, primarily due to increased planned outages;

• an increase of $16 million related to employee benefit costs;

• an increase of $14 million related to costs for renewable energy programs and similar regulatory programs, which are partially offset in operating revenues and purchased power;

• an increase of $16 million related to corporate resource costs;

• a decrease of $3 million for other miscellaneous factors.

• an increase of $2 million related to nuclear generation costs;

• 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;

• an increase of $1 million related to non-nuclear generation costs, primarily due to increased operating costs;

• a decrease of $11 million related to transmission, distribution, and customer service costs;

• a decrease of $13 million related to employee benefit costs;

• an increase of $4 million for other miscellaneous factors.

Depreciation and amortization.

Depreciation and amortization expenses were $101 million higher for the year ended December 31, 2024, compared to the prior-year period, primarily due to increased plant in service and intangible assets.

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 AFUDC, were $60 million higher for the year ended December 31, 2024, compared to the prior-year period, primarily due to higher debt balances and higher interest rates in the current period, higher allowance for borrowed funds and lower allowance for equity funds.

Other income and expenses, net.

Other income and expenses, net were $4 million higher for the year ended December 31, 2024, compared to the prior-year period, primarily due to the gain on the sale of BCE, partially offset by 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 on the sale of BCE.

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 $34 million higher for the year ended December 31, 2024, compared with the prior-year period, primarily due to higher pre-tax income, and lower tax benefits from AFUDC equity, partially offset by higher tax credits.

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

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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 below 40%.

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.

At December 31, 2024, APS’s common equity ratio, as defined, was 52%.

Its total shareholder equity was approximately $8.3 billion, and total capitalization was approximately $15.9 billion.

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.

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 loan 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.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt.

Regulatory lag may delay recovery and affect operating cash flows.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term

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 ass ets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.

On June 12, 2024, Pinnacle West contributed $450 million into APS in the form of an equity infusion.

APS used this contribution to repay short-term indebtedness.

On 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 commercial paper borrowings and for other general corporate purposes.

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.

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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.

As of December 31, 2024, approximately $850 million of common stock is available to be issued under the ATM program, which takes into account the forward sale agreement in effect as of December 31, 2024.

In addition to the ATM program, Pinnacle West has forward sale agreements from an equity offering in February 2024 in effect as of December 31, 2024.

In December 2024, Pinnacle West partially settled the February 2024 Forward Sale Agreements with the issuance of 5,377,115 shares of common stock and received net proceeds of $345 million.

The proceeds were recorded in equity.

At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock in exchange for cash of $377 million.

For additional information regarding common stock issuances, the ATM program, and outstanding forward sale agreements, see Note 13.

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

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Pinnacle West Consolidated

Year Ended December 31,

2025 2024 Net Change

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Net cash flow provided by financing activities

323 487 (164)

Net decrease in cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

$ 3 $ (1) $ 4

Arizona Public Service Company

APS Consolidated

Year Ended December 31,

2025 2024 Net Change

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Net cash flow provided by financing activities

Net decrease in cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

$ — $ (1) $ 1

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2025 Compared with 2024.

Pinnacle West’s consolidated net cash provided by operating activities was $1,610 million in 2024 compared to $1,207 million in 2023, an increase of $403 million in net cash provided, primarily due to $447 million higher cash receipts from electric revenues, $236 million lower fuel and purchased power costs, $15 million change in net collateral, partially offset by $125 million higher income taxes paid, $104 million higher payments for operations and maintenance costs, $49 million higher interest payments and $17 million of other changes in working capital.

The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s higher income tax cash payments to Pinnacle West and other changes in working capital.

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.

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We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.

Under ERISA, the qualified pension plan was estimated to be 100% funded as of January 1, 2025, and was 113% as of January 1, 2024.

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.

We did not make any contributions to our pension plan in 2024 and 2023.

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;

Regarding contributions to our other postretirement benefit plan, we did not make any contributions in 2024 or 2023 and do not expect to make any contributions in 2025, 2026 or 2027.

The Company was reimbursed $27 million in 2024, $23 million in 2023, and $26 million in 2022 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

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.

For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 99% funded as of December 31, 2024, and our postretirement benefit plans were 195% funded, as measured for GAAP purposes at December 31, 2024.

See Note 7 for additional details.

Investing Cash Flows

2025 Compared with 2024.

Pinnacle West’s consolidated net cash used for investing activities was $1,934 million in 2024 compared to $1,694 million in 2023, an increase of $240 million primarily related to $272 million of increased capital expenditures and $21 million of additional investing activity, partially offset by proceeds of $61 million from the BCE Sale.

The difference between APS’s and Pinnacle West’s net cash used for investing activities primarily relates to the BCE Sale and investments into the Captive Insurance Cell VIE.

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:

The following table summarizes the estimated capital expenditures for the next three years (dollars in millions):

Capital Expenditures

(dollars in millions)

Estimated for the Year Ended

Estimated for the Year Ending December 31,

2026 2027 2028

Gas and Other Generation $ 635 $ 550 $ 490

Nuclear Generation 170 185 215

Renewables and Energy Storage Systems (“ESS”) 335 165 430

Other Generation (a) 420 540 335

Renewables and Energy Storage 20 5 5

Distribution 765 795 750

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Total APS $ 2,600 $ 2,650 $ 2,700

(a) Includes gas generation and environmental projects.

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 clean resources, including nuclear plants, renewables and ESS, as well as additions and improvements to existing fossil plants.

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.

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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 will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

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 $323 million in 2024 compared to $487 million in 2023, a decrease of $164 million in net cash provided primarily due to $842 million higher long-term debt repayments and a net decrease in short-term debt borrowings of $283 million, partially offset by $624 million in higher issuances of long-term debt and an equity issuance of $345 million.

APS’s consolidated net cash provided by financing activities was $375 million in 2024 compared to $412 million in 2023, a decrease of $37 million in net cash provided primarily due to a net decrease in

short-term borrowings of $374 million, $250 million higher long-term debt repayments and $50 million in lower issuances of long-term debt, partially offset by $645 million in higher equity infusions.

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.

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Equity Offerings .

Pinnacle West 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.

On December 31, 2024 , Pinnacle West could have settled the outstanding November 2024 ATM Forward Sale Agreement with the physical delivery of 552,833 shares of Pinnacle West common stock in exchange for cash of approximately $50 million .

As of December 31, 2024 , Pinnacle West has not received any proceeds relating to the November 2024 Forward Sale Agreement.

In addition to the ATM program, Pinnacle West entered into certain equity forward sale agreements in February 2024, which were partially settled in December 2024 with the issuance of 5,377,115 shares of common stock.

In connection with the partial settlement, Pinnacle West received net proceeds of $345 million.

At December 31, 2024, Pinnacle West could have settled the remaining February 2024 Forward Sale Agreements with the issuance of 5,863,486 shares of common stock in exchange for cash of $377 million.

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.

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

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)

Initial Price 2,199,415 $ 90.1038 (a) (d) $ 198,176

(a) Subject to certain adjustments.

(b) Physical delivery.

(d) Weighted-average price for the total ATM Program.

Other Financing Matters.

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For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.

At December 31, 2024, the ratio was approximately 59% for Pinnacle West and 49% for APS.

Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt.

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 the required interest and principal payments in the event of a rating downgrade.

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 loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.

All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank

agreements if APS were to default under certain other material agreements.

Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

On December 17, 2024, the ACC issued a financing order reaffirming the short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power) and approving an increase of the long-term debt limit to $9.5 billion and a limit of permitted annual equity infusions into APS equal to 2.5% of APS’s total assets each calendar year on a three-year rolling average basis, subject to APS’s equity ratio remaining below the most recently approved rate case capital structure plus 50 basis points.

See Note 6 for additional long-term debt provisions and further discussions of liquidity matters.

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

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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.

On March 7, 2024, S&P affirmed the ratings and revised Pinnacle West’s and APS’s outlooks from negative to stable.

On March 20, 2024, Moody’s downgraded both Pinnacle West’s and APS’s credit ratings by a notch and revised their outlooks from negative to stable.

On March 26, 2024, Fitch affirmed APS’s ratings and downgraded Pinnacle West’s ratings by a notch.

Fitch revised the outlook for both Pinnacle West and APS from negative to stable.

At this time, we believe we have sufficient available liquidity resources to respond to a potential downward revision to our credit ratings.

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See Notes 8 and 14.

Purchase obligations include capital expenditures and other obligations.

Purchase obligations may include commitments for capital expenditures and other obligations.

Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments.

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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 OCI and result in lower future earnings.

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.

20 unchanged sentences

Actuarial Assumption (a) Impact on

Plans Impact on

Pension Plans

(Assets) Liabilities Impact on

Expense (Benefit)

Discount rate (b):

12 unchanged sentences

Postretirement

Benefit Plans Impact on Other

Postretirement

Benefit Expense

Benefit Plans

(Assets) Liabilities Impact on Other

Postretirement Benefit

Expense (Benefit)

Discount rate (b):

37 unchanged sentences

OTHER ACCOUNTING MATTERS

We adopted new accounting standard, ASU 2023-07, Segment Reporting:

Improvements to Reportable Segment Disclosures, on December 31, 2024.

We will adopt new accounting standard, ASU 2023-09, Income Taxes:

Improvements to Income Tax Disclosures, on December 31, 2025.

We are currently evaluating the disclosure impacts of the pending adoption of the new accounting standard, ASU 2024-03, Income Statement Reporting:

Expense Disaggregation Disclosures, effective for us on December 31, 2027.

See Note 21 for additional information relating to new accounting standards.

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.

• 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

73 unchanged sentences

Mark-to-market of net positions at beginning of year $ (42) $ (120)

Decrease (increase) in regulatory asset 78 (216)

Decrease in regulatory asset 16 78

Mark-to-market of net positions at end of year $ (26) $ (42)

21 unchanged sentences

DISCLOSURES ABOUT MARKET RISK

See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risks.

See “Market and Credit Risks” in Part II, Item 7 above for a discussion of quantitative and qualitative disclosures about market risks.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis