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Item 1. Business

2026-02-25 compared with 2025-02-25 · 318 added, 329 removed, 429 unchanged (60% of the section changed)

Pinnacle West

Pinnacle West is a holding company incorporated in Arizona that conducts business through its subsidiaries.

We derive essentially all of our revenues and earnings from our wholly-owned subsidiary, APS.

APS is incorporated in Arizona and is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.

Pinnacle West’s other active subsidiaries are El Dorado, an Arizona corporation, and PNW Power, a Delaware limited liability company.

BCE was a subsidiary of Pinnacle West, but was sold in January 2024.

Additional information related to these subsidiaries is provided later in this report.

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona

with consolidated assets of approximately $30 billion.

We derive essentially all of our revenues and earnings from our principal subsidiary, APS.

Since 1886, APS and its affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

APS is Arizona’s largest and longest-serving electric company and generates safe, affordable electricity in 11 of Arizona’s 15 counties.

Our other active subsidiaries are El Dorado and PNW Power.

Our 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.

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APS currently provides electric service to approximately 1.4 million customers.

We own or lease 6,540 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity.

We own or lease 6,257 MW of regulated generation capacity, and we hold a mix of both long-term and short-term PPAs for additional capacity.

During 2025, no single purchaser or user of energy accounted for more than 1.9% of our electric revenues.

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Energy Sources and Resource Planning

To serve its customers, APS obtains power through its various generation stations and through purchased power agreements.

To serve its customers, APS obtains power through its various generation stations and through PPAs.

Resource planning is an important function necessary to meet Arizona’s future energy needs.

APS’s sources of energy by type used to supply energy to Native Load customers during 2025 were approximately as follows:

*Utility Scale Renewables include energy from biogas, biomass, geothermal, solar, and wind.

The share of APS’s energy supply being derived from clean resources was approximately 54% in 2024, which includes energy from nuclear, renewables and DSM.

Clean Energy Focus Initiatives

In response to climate change, APS has undertaken a number of initiatives to reduce carbon, including renewable energy procurement and development, and promotion of programs and rates that promote energy conservation, renewable energy use, and energy efficiency.

See “Energy Sources and Resource Planning — Current and Future Resources” below for details of these plans and initiatives.

APS currently has a diverse portfolio of renewable resources, including biogas, biomass, geothermal, solar, and wind.

In addition, in January 2020, APS announced its Clean Energy Commitment, a three-pronged approach aimed at ultimately eliminating carbon-emitting resources from its electric generation resource portfolio.

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.

Among other strategies, APS intends to achieve these goals through various methods such as relying on Palo Verde, one of the nation’s largest producers of carbon-free energy;

increasing clean energy resources, including renewables;

developing energy storage;

exiting from coal-generated electricity;

APS has a diverse portfolio of existing and planned resources, including biomass, biogas, coal, energy storage, geothermal, natural gas, solar, and wind.

APS has an aspirational goal to be carbon-neutral by 2050, meaning that for any GHG emissions still produced by generation resources in 2050, APS will aim to offset these emissions elsewhere.

In 2025, the share of APS’s energy supply derived from clean resources was approximately 58%, which includes energy from nuclear, renewables, and DSM as well as PPAs with clean resources.

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

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.

The latest IRP was released in 2023 and APS is currently developing its next IRP due to be filed with the ACC in August 2026.

To help ensure competitive costs for resources, 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.

As energy demand in Arizona continues to grow, APS remains committed to delivering reliable and affordable service to its customers, with a goal of achieving top quartile reliability compared to its

Among other strategies, APS intends to achieve this goal through various methods such as relying on Palo Verde, one of the nation’s largest producers of carbon-free energy;

seeking a balanced energy mix;

managing demand with a modern interactive grid;

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and optimizing regional resources.

Management takes into consideration climate change and other environmental risks in its strategy development, business planning, and enterprise risk management processes.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information about APS’s Clean Energy Commitment.

Over this same period of time, APS also intends to harden its infrastructure in order to improve climate resiliency, which involves system and operational improvements aimed at reducing the impact of extreme weather events and other climate-related disruptions upon APS’s operations.

APS also intends to harden its infrastructure in order to improve resiliency, which involves system and operational improvements aimed at reducing the impact of extreme weather events and other disruptions upon APS’s operations.

Wildfire safety remains a critical focus for APS and other utilities.

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

Among other resiliency strategies, APS anticipates increasing investments in a modern and more flexible electricity grid with advanced distribution technologies.

APS plans to continue its forest management programs aimed at reducing wildfires, as those risks become compounded by shorter, drier winters and longer, hotter summers as a result of climate change.

APS prepares an annual inventory of GHG emissions from its operations.

For APS’s operations involving fossil-fuel electricity generation and electricity transmission and distribution, APS’s annual GHG inventory is reported to the EPA under the EPA GHG Reporting Program.

In addition to reporting to the EPA, we publicly report Scope 1 and 2, as well as a limited number of Scope 3, GHG emissions.

This data is then communicated to the public in Pinnacle West’s annual Corporate Responsibility Report as performance data and in CDP Reports, which are available on our website ( www.pinnaclewest.com/corporate-responsibility ).

The reports provide information related to the Company and its approach to sustainability and its workplace and environmental performance.

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

Generation Facilities

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Palo Verde Leases — In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back approximately 42% of its share of Palo Verde Unit 2 and certain common facilities.

The leaseback was originally scheduled to expire at the end of 2015 and contained options to renew the leases or to purchase the leased property for fair market value at the end of the lease terms.

On July 7, 2014, APS exercised the fixed rate lease renewal options.

The exercise of the renewal options originally resulted in APS retaining the assets through 2023 under one lease and 2033 under the other two leases.

On April 1, 2021, APS executed an amendment relating to the lease agreement with the term ending in 2023.

The amendment extends the lease term for this lease through 2033 and changes the lease payment.

As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements.

At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

In 2025, APS purchased two of the three leased interests.

The remaining lease for approximately 5.2% of Unit 2 expires in 2033.

At the end of the lease renewal period, APS will have the option to purchase the leased assets at their fair market value, extend the lease for up to two years, or return the assets to the lessor.

See Note 12 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

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In June 2008, the DOE submitted its Yucca Mountain construction authorization application to the NRC, but in March 2010, the DOE filed a motion to dismiss with prejudice the Yucca Mountain construction authorization application.

Several legal proceedings followed challenging DOE’s withdrawal of its Yucca Mountain construction authorization application and the NRC’s cessation of its review of the Yucca

Mountain construction authorization application, which were consolidated into one matter at the U.S.

Several legal proceedings followed challenging DOE’s withdrawal of its Yucca Mountain construction authorization application and the NRC’s cessation of its review of the Yucca Mountain construction authorization application, which were consolidated into one matter at the U.S.

Court of Appeals for the District of Columbia Circuit (the “D.C.

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In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025.

APS has recovered costs for ten claims pursuant to the terms of the August 15, 2014 settlement agreement, for ten separate time periods during July 1, 2011 through October 31, 2023.

APS is currently evaluating a proposed extension to the settlement to cover costs paid through December 31, 2028.

APS has recovered costs for eleven claims pursuant to the terms of the August 15, 2014 settlement agreement, for eleven separate time periods during July 1, 2011 through October 31, 2024.

The DOE has approved and paid approximately $174.3 million for these claims (APS’s share is approximately $50.7 million).

The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income.

In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers.

On October 31, 2024, APS filed its eleventh claim pursuant to the terms of the August 15, 2014, settlement agreement in the amount of approximately $18 million (APS’s share is approximately $5.3 million).

In accordance with the ACC’s decision from APS’s 2017 rate case, this regulatory liability is being refunded to customers.

On October 31, 2025, APS submitted its twelfth claim pursuant to the terms of the settlement agreement in the amount of approximately $15.4 million (APS’s share is approximately $4.5 million).

In February 2026, the DOE approved approximately $15.4 million of this claim.

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Circuit issued its final decision, rejecting all remaining legal challenges to the Continued Storage Rule.

On August 8, 2016, the D.C.

Circuit denied a petition for rehearing.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.

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See Note 18 for additional information about APS’s nuclear decommissioning trusts.

Palo Verde Liability and Insurance Matters — See “Palo Verde Generating Station — Nuclear Insurance” in Note 10 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

Palo Verde Liability and Insurance Matters — See “Palo Verde Generating Station — Nuclear Insurance” in Note 14 for a discussion of the insurance maintained for Palo Verde by the Palo Verde participants, including APS.

Natural Gas and Oil Fueled Generating Facilities

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Fuel oil is acquired under short-term purchases delivered by truck directly to the power plants.

In 2024, APS contracted for the addition of two combustion turbines (approximately 90 MW in total) at Sundance, which are expected to be in service in 2026, and the addition of eight combustion turbines (approximately 397 MW total) at Redhawk, which are expected to be in service in 2028.

In 2024, APS contracted for the addition of two combustion turbines (approximately 90 MW in total) at Sundance, which entered into service in 2025, and the addition of eight combustion turbines (approximately 397 MW total) at Redhawk, which are expected to be in service in 2028.

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.

Coal Fueled Generating Facilities

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APS has a total entitlement from Four Corners of 970 MW.

APS plans to exit coal-fired generation as part of its portfolio of electricity generating resources, including Four Corners, by 2031.

NTEC, a company formed by the Navajo Nation to own the mine that serves Four Corners and develop other energy projects, is the coal supplier for Four Corners.

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APS closed Unit 2 on October 1, 2015.

Following the closure of Unit 2, APS has a total entitlement from Cholla of 380 MW.

Following the closure of Unit 2, APS had a total entitlement from Cholla of 380 MW.

In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect for Cholla on April 26, 2017.

In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020.

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

APS purchased all of Cholla coal requirements from a coal supplier that mines the coal under long-term leases of coal reserves with the federal and state governments and private landholders.

APS elected not to extend the coal and transportation agreements that expired on December 31, 2024, as Cholla operations are expected to conclude in 2025.

APS ceased coal-burning operations at Cholla in March 2025 and formally retired Cholla Units 1 and 3 on April 30, 2025.

APS is currently recovering in rates a return on the net-book value of its interest in Cholla and associated depreciation costs.

In APS’s rate case application filed in 2025 (the “2025 Rate Case”), APS requested recovery in rates of the ongoing environmental remediation and CCR closure costs associated with Cholla and any remaining unrecovered plant costs.

The 2025 Rate Case also includes a request for an ongoing deferral order relating to anticipated increased environmental remediation costs relating to Cholla that may be incurred after the 2025 Rate Case proceeding.

Navajo Plant — The Navajo Plant was a 3-unit coal-fired power plant located in northern Arizona.

Salt River Project operated the plant and APS owned a 14% interest in Units 1, 2 and 3.

APS had a total

entitlement from the Navajo Plant of 315 MW.

The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease.

APS had a total entitlement from the Navajo Plant of 315 MW.

The Navajo Plant site was leased from the Navajo Nation and subject to an easement from the federal government.

The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, which allowed for decommissioning activities to begin after the plant ceased operations in November 2019.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026.

APS will seek continued recovery in rates for the book value of its remaining investment in the plant.

See Note 3 for details related to the resulting regulatory asset plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material.

See Note 10 for information regarding APS’s coal mine reclamation obligations related to these coal-fired plants.

Solar Facilities

APS developed utility scale solar resources through the 180 MW ACC-approved AZ Sun Program, investing approximately $675 million in this program.

These facilities are owned by APS and are located in multiple locations throughout Arizona.

In addition to the AZ Sun Program, APS developed the 44 MW Red Rock Solar Plant and the 150 MW Agave Solar Plant, each of which it owns and operates, and has contracted for the construction of the 168 MW Ironwood Solar Plant.

APS owns and operates more than thirty small solar systems around the state.

Together they have the capacity to produce approximately 4 MW of renewable energy.

This fleet of solar systems includes a 3 MW facility located at the Prescott Airport and 1 MW of small solar systems in various locations across Arizona.

APS has also developed solar photovoltaic DG systems installed as part of the Community Power Project in Flagstaff, Arizona.

The Community Power Project, approved by the ACC on April 1, 2010, was a pilot program through which APS owns, operates, and receives energy from approximately 1 MW of solar photovoltaic DG systems located within a certain test area in Flagstaff, Arizona.

The pilot program is now complete and as part of the 2017 Rate Case Decision, the participants have been transferred to the Solar Partner Program described below.

Additionally, APS owns 13 MW of solar photovoltaic systems installed across Arizona through the ACC-approved Schools and Government Program.

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid.

The first stage of the program, called the “Solar Partner Program,” placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties.

The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016.

The costs for this program have been included in APS’s rate base as part of the 2017 Rate Case Decision.

In the 2017 Rate Case Decision, the ACC also approved the “APS Solar Communities” program.

APS Solar Communities (formerly AZ Sun II) is a three-year program authorizing APS to spend $10

million to $15 million in capital costs each year to install utility-owned DG systems on low to moderate income residential homes, non-profit entities, Title I schools, and rural government facilities.

The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.

Currently, APS has installed 14 MW of DG systems under the APS Solar Communities program.

In the 2019 Rate Case decision, the ACC authorized APS to spend $20 million to $30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the decision.

Subsequently, on March 5, 2024, the ACC ordered APS not to expand or extend the APS Solar Communities program.

Consistent with that decision, the Solar Communities program has been discontinued and APS stopped enrolling new customers.

APS will continue work on projects that were enrolled prior to that decision.

Renewable Energy Portfolio

To date, APS has a diverse portfolio of existing and planned renewable resources totaling 7,660 MW, including biogas, biomass, geothermal, solar, and wind.

Of this portfolio, 3,608 MW are currently in operation and 4,052 MW are under contract for development or are under construction.

Renewable resources in operation include 416 MW of facilities owned by APS, 1,465 MW of long-term purchased power agreements, and an estimated 1,727 MW of customer-sited, third-party owned distributed energy resources.

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.

APS’s strategy to achieve its RES requirements includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS.

See “Energy Sources and Resource Planning — Generation Facilities — Solar Facilities” above for information regarding APS-owned solar facilities and “Energy Sources and Resource Planning — Generation Facilities — Energy Storage” below for more information regarding APS-owned energy storage facilities.

The following table summarizes APS’s renewable energy sources currently in operation and under development as of the date of this report.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant.

APS will seek continued recovery in rates or the book value of its remaining investment in the plant.

See Note 8 for details related to the regulatory treatment of these coal-fired plants and Note 14 for information regarding APS’s coal mine reclamation obligations related to these coal-fired plants.

APS Owned Renewable and Energy Storage Resources

APS owns various utility scale solar resources and DG systems developed through various ACC-approved programs as well as the ASRFP process.

The following table summarizes APS’s owned renewable resources currently in operation and 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.

Location Actual/

Capacity amounts are approximate.

Location Actual/Target

Date Net Capacity (MW) In Operation Net Capacity (MW)

Planned/Under

AZ Sun Program:

Paloma Gila Bend, AZ 2011 17

Cotton Center Gila Bend, AZ 2011 17

Hyder Phase 1 Hyder, AZ 2011 11

Hyder Phase 2 Hyder, AZ 2012 6

Hyder I Hyder, AZ 2012 17

Chino Valley Chino Valley, AZ 2012 20

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Desert Star Buckeye, AZ 2015 10

Subtotal AZ Sun Program 180 —

Multiple Facilities AZ Various 4

Red Rock Red Rock, AZ 2016 44

Agave Solar Arlington, AZ 2023 150

Ironwood Solar Dateland, AZ 2026 168

Ironwood Solar Dateland, AZ (a) 168

Multiple Facilities AZ Various 4

Distributed Energy:

APS Owned (a) AZ Various 38

APS Owned (c) AZ Various 41

Total APS Owned 419 168

(a) This project met plant in service criteria as of December 31, 2025.

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

(c) Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.

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 further our understanding of how storage works with other advanced technologies and the grid.

The following table summarizes APS’s owned energy storage currently in operation and 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.

Capacity amounts are approximate and represent the maximum designed MW the site can provide for three hours, unless noted otherwise.

Location Actual/Target

Date Net Capacity (MW) In Operation Net Capacity (MW)

Planned/Under

Paloma Gila Bend, AZ 2023 17

Cotton Center Gila Bend, AZ 2023 17

Hyder I Hyder, AZ 2023 16

Chino Valley (a) Chino Valley, AZ 2023 19

Hyder II Hyder, AZ 2023 14

Foothills Yuma, AZ 2023 35

Gila Bend Gila Bend, AZ 2023 32

Desert Star Buckeye, AZ 2022 10

Red Rock (a) Red Rock, AZ 2023 41

Agave (a) Arlington, AZ (b) 150

Total APS Owned 201 150

(a) Capacity amounts represent the maximum designed MW the site can provide for four hours.

(b) This project met plant in service criteria as of December 31, 2025.

PPAs and Other Third-Party Owned Resources

In addition to its own available generation and storage capacity, APS purchases electricity under various arrangements, including through long-term contracts, purchases through short-term markets to supplement its owned or leased generation and hedge its energy requirements, and other arrangements with third parties, such as customer programs like APS’s Storage Rewards Pilot Program.

A portion of APS’s purchased power expense is netted against wholesale sales on the Consolidated Statements of Income.

APS continually assesses its need for additional capacity resources to ensure system reliability.

APS’s non-renewable purchased power under long-term contracts as of the date of this report is summarized in the table below.

Capacity amounts are approximate.

Type Dates Available Net Capacity (MW)

Tolling Agreement May 1 through April 30, 2021-2025 463

Extension Term May 1 through October 31, 2025-2032 525

Tolling Agreement June 1 through September 30, 2020-2025 565

First Extension Term May 1 through October 31, 2026 575

Second Extension Term May 1 through October 31, 2027-2038 600

Tolling Agreement June 1 through September 30, 2020-2026 570

Extension Term May 1 through October 31, 2027-2034 600

Non-APS owned renewable energy resources currently in operation and planned/under development as of the date of this report are summarized in the table below.

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.

Capacity amounts are approximate.

Location Actual/ Target

Operation Date Term

(Years) Net Capacity

In Operation Net Capacity

Planned/Under Development

Solana Gila Bend, AZ 2013 30 250

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Sunstreams 4 Arlington, AZ 2025 20 300

Serrano Solar Pima and Pinal County, AZ 2025 20 170

Serrano Solar Pima & Pinal County, AZ 2025 20 170

CO Bar Solar C Coconino County, AZ 2027 20 206

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Total PPAs 2,305 2,981

Distributed Energy

Distributed Energy (a)

Third-party Owned AZ Various 1,773 82

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Total Distributed Energy 1,806 82

Total Renewable Portfolio 3,608 4,052

(a) Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.

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

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

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.

See “Item 7 — Management’s Discussion and Analysis of Financial Condition — Clean Energy Commitment — Energy Storage” for a table summarizing the resources in APS’s energy storage portfolio that are in operation and under development as of the date of this report.

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

Purchased Power Contracts

In addition to its own available generating capacity, APS purchases electricity under various arrangements, including long-term contracts and purchases through short-term markets to supplement its owned or leased generation and hedge its energy requirements.

A portion of APS’s purchased power expense is netted against wholesale sales on the Consolidated Statements of Income.

APS continually assesses its need for additional capacity resources to assure system reliability.

In addition, APS has also entered into several PPAs for energy storage.

See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for details on our energy storage PPAs.

Purchased Power Capacity — APS’s purchased power capacity under long-term contracts as of the date of this report is summarized in the table below.

All capacity values are based on net capacity unless otherwise noted.

Type Dates Available Capacity

Purchase Agreement (a) Year-round through June 14, 2025 46

Demand Response Agreement Summer seasons through 2025 75

Tolling Agreement May 1 through April 30, 2021-2025 463

Extension Term May 1 through October 31, 2025-2032 525

Tolling Agreement June 1 through September 30, 2020-2026 565

Extension Term May 1 through October 31, 2026-2031 565

Tolling Agreement June 1 through September 30, 2020-2026 570

Extension Term May 1 through October 31, 2027-2034 600

Renewable Energy (b) Various 1,465

(a) Up to 46 MW of capacity is available;

however, the amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually.

(b) Does not include MW of capacity planned or under development.

See “Energy Sources and Resource Planning — Generation Facilities — Renewable Energy Portfolio” for more details on renewable energy power purchase agreements.

Total 4,111 3,063

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

Non-APS owned energy storage resources currently in operation and planned/under development as of the date of this report are summarized in the table below.

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.

Capacity amounts are approximate and reported as nameplate capacity in MW and represent the maximum designed MW the site can provide for four hours.

Location Actual/ Target

Operation Date

(Years) Nameplate

Capacity (MW)

In Operation Nameplate Capacity

Planned/Under Development

Mesquite 5 Tonopah, AZ 2023 20 60

West Wing 1 Peoria, AZ 2024 20 80

El Sol Phoenix, AZ 2024 20 50

Sun Streams 3 Arlington, AZ 2024 20 215

Yuma Yuma, AZ 2025 20 67

Westwing 2 Peoria, AZ 2025 20 120

Harquahala Sun 2 Quartzsite, AZ 2025 20 300

Scatterwash 1 Phoenix, AZ 2025 20 170

Pluto BESS Goodyear, AZ 2025 20 75

Papago Tonopah, AZ 2025 20 300

Scatterwash 2 Phoenix, AZ 2025 20 85

Seranno Pima County, AZ 2025 20 214

Sun Streams 4 Arlington, AZ 2025 20 300

Justice Buckeye, AZ 2026 20 150

Catclaw Buckeye, AZ 2026 20 250

Hashknife 1 Navajo County, AZ 2026 20 275

Beehive Peoria, AZ 2026 20 250

Desert Bloom Peoria, AZ 2026 20 150

Maricopa Energy Center Phase 1 Maricopa County, AZ 2026 20 183

Maricopa Energy Center Phase 2 Maricopa County, AZ 2026 20 367

Kitt Eloy, AZ 2026 20 100

White Tank Avondale, AZ 2027 20 100

Pioneer Yuma, AZ 2027 20 300

Co Bar C Coconino County, AZ 2027 20 206

Hashknife 2 Navajo County, AZ 2027 20 200

Harquahala Flats Tonopah, AZ 2027 20 225

Snowflake PVS Snowflake, AZ 2027 20 475

Harquahala Flats 2 Tonopah, AZ 2027 20 225

Total BESS PPAs 2,036 3,456

Distributed BESS

Third-party Owned AZ Various 103 37

Total 2,139 3,493

Current and Future Resources

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In Arizona, demand for power peaks during the hot summer months.

APS’s 2024 peak one-hour demand on its electric system was recorded on August 4, 2024, at 8,210 MW, compared to the 2023 peak of 8,162 MW recorded on July 15, 2023.

APS’s reserve margin at the time of the 2024 peak demand, calculated using system load serving capacity, was 15%.

For 2025, APS is procuring market resources to maintain its minimum 16% planning reserve criteria.

APS’s 2025 peak one-hour demand on its electric system was recorded on August 7, 2025, at 8,648 MW, compared to the 2024 peak of 8,210 MW recorded on August 4, 2024.

reserves across all hours of the year to respond to system events and uncertainty in load and resource

For 2026, APS is building resources and has procured long-term PPAs to meet the industry standard of reliability for its growing load and increased weather volatility.

Future Resources and Resource Plan

ACC rules require utilities to develop 15-year Integrated Resource Plans (“IRP”) which describe how the utility plans to serve customer load in the plan timeframe.

ACC rules require utilities to develop 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.

The ACC reviews each utility’s IRP to determine if it meets the necessary rule requirements and whether it should be acknowledged.

On May 1, 2023, APS, Tucson Electric Power Company, and UNS Electric, Inc.

filed a joint request for an extension to file the IRPs from August 1 to November 1.

On June 21, 2023, the ACC granted the extension.

As a result, APS filed its 2023 IRP on November 1, 2023.

On January 31, 2024, stakeholders filed comments regarding the IRP, and APS filed its response to stakeholder comments on May 31, 2024.

On July 31, 2024, the ACC held an IRP workshop where utilities and stakeholders presented on the 2023 IRPs.

On October 8, 2024, the ACC acknowledged APS’s 2023 IRP and approved certain amendments to the IRP process, including requirements for APS to demonstrate resource adequacy prior to exiting Four Corners as well as analysis of impacts from western market participation and planned resource requirements in the next IRP.

See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Clean Energy Focus Initiatives” and “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for information regarding future plans for energy storage.

See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities” above for information regarding plans for Cholla, Four Corners and the Navajo Plant.

APS’s next IRP is in process and due to be filed with the ACC in August 2026.

Western Energy Imbalance Market and Wholesale Market

In 2016, APS began to participate in the Western Energy Imbalance Market (“WEIM”), a voluntary, real-time optimization market operated by the CAISO.

In 2016, APS began to participate in the WEIM, a voluntary, real-time optimization market operated by the CAISO.

The WEIM allows for rebalancing supply and demand in 15-minute blocks and dispatching generation every five minutes, instead of the traditional one-hour blocks.

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”).

APS continues to expect that its participation in the 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 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 has made a market decision to pursue participation in SPP Markets+, which is expected to go live in October 2027.

In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool and is transitioning to full binding participation in 2027 or 2028.

These regional efforts are driven by the objectives of reducing customer cost and improving reliability.

Energy Modernization Plan

In June 2021, the ACC adopted clean energy rules based on a series of ACC amendments to the final energy rules.

The adopted rules require 100% clean energy by 2070 and the following interim standards for carbon reduction from a baseline carbon emissions level:

50% reduction by December 31, 2032;

65% reduction by December 31, 2040;

80% reduction by December 31, 2050, and 95% reduction by December 31, 2060.

Since the adopted clean energy rules differed substantially from the original Recommended Opinion and Order (“ROO”), supplemental rulemaking procedures were required before the rules could become effective.

On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process.

Instead, the ACC opened a new docket to consider all-source request for proposals (“ASRFP”) requirements and the IRP process.

During the August 2022 ACC Open Meeting, the ACC voted to postpone a decision on the ASRFP and IRP rulemaking package until 2023.

On May 26, 2023, the ACC opened a new docket to review articles within the Arizona Administrative Code related to Resource Planning, the Renewable Energy Standard and Tariff, and Electric Energy Efficiency Standards.

On January 9, 2024, the ACC approved a rulemaking process to begin on this matter.

During the ACC Open Meeting on February 6, 2024, the ACC approved motions to direct ACC Staff to include recommendations to repeal the current Electric Energy Efficiency and Renewable Energy Standard rules during the rulemaking process.

On August 21, 2024, ACC Staff proposed amendments striking the rules and filed preliminary economic, small business, and consumer impact statements, consistent with the formal rulemaking process.

APS cannot predict the outcome of this matter.

See Note 3 for additional information related to these energy rules.

Renewable Energy Standard

In 2006, the ACC approved the RES.

Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including, for example, solar, wind, biomass, biogas and geothermal technologies.

In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.

Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process.

Since the adopted clean energy rules differed substantially from the original ROO, supplemental rulemaking procedures were required before the rules could become effective.

On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process.

Instead, the ACC opened a new docket to consider ASRFP requirements and the IRP process.

See “Energy Modernization Plan” above for more information.

On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million.

APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million.

This budget included funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the continuation of the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision.

APS’s budget proposal supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2022.

On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the ACC’s consideration at a future date.

On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $86.2 million, excluding any funding offsets.

This budget contained funding for programs to comply with ACC-approved initiatives, including the 2019 Rate Case decision.

APS’s budget proposal supported existing approved projects and commitments and requested a waiver of the RES residential and non-residential distributed energy requirements for 2022.

On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023.

On June 30, 2023, APS filed its 2024 RES Implementation Plan and proposed a budget of approximately $95.1 million.

APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES renewable energy credit requirements to demonstrate compliance with the Annual Renewable Energy Requirement for 2023.

The ACC has not yet ruled on the 2024 RES Implementation Plan.

APS cannot predict the outcome of this proceeding.

On July 1, 2024, APS filed its 2025 RES Implementation Plan and proposed a budget of approximately $92.7 million.

The ACC has not yet ruled on the 2025 RES Implementation Plan.

APS cannot predict the outcome of this proceeding.

On June 14, 2021, APS filed an application for approval of its Green Power Partners Program (“GPP”).

On September 1, 2021, the ACC approved the application.

On June 28, 2024, APS filed an application for approval of modifications to the GPP and requested a renewable generation renewable energy credits waiver.

The ACC has not yet ruled on the GPP application.

APS cannot predict the outcome of this proceeding.

Demand Side Management

On January 1, 2011, Arizona regulators adopted an EES of 22% cumulative annual energy savings by 2020 to increase energy efficiency and other DSM programs encouraging customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy.

APS achieved the 22% EES in 2021.

See Note 3 for information regarding energy efficiency, other DSM obligations and the Energy Modernization Plan.

Competitive Environment and Regulatory Oversight

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APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts, and similar types of governmental or non-profit organizations.

In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements.

In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet

some or all of their own energy requirements.

This practice is becoming more popular with customers installing or having installed products such as rooftop solar panels to meet or supplement their energy needs.

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.

On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules.

On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules.

On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules.

During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken.

In April 2022, the Arizona Legislature passed, and the Governor signed a bill that repealed the electric deregulation law that had been in place in Arizona since 1998.

On August 27, 2024, the ACC administratively closed this docket due to inactivity and obsolescence.

While historically this practice has been largely focused on customers installing behind the meter technologies, such as rooftop solar panels or back-up generators to meet or supplement their energy needs, today APS and utilities broadly are seeing a rise in large customers seeking to develop or accelerate large, utility scale generation projects to serve their energy needs.

This is creating the need for new and creative commercial and regulatory constructs to ensure reliability, cost recovery, and the equitable allocation of costs among customer groups.

FERC regulates rates for wholesale power sales and transmission services.

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APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and clean energy development.

The capital expenditures table presented in the “Liquidity and Capital Resources” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report includes new APS transmission projects, along with other transmission costs for upgrades and replacements, including those for data center and semi-conductor manufacturing development.

The capital expenditures table presented in the “Liquidity and Capital Resources” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report includes new APS transmission projects, along with other transmission costs for upgrades and replacements, including those for data center and semi-conductor manufacturing development.

To prioritize reliability and meet substantial growth in residential and commercial 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 represents a significant upgrade to APS’s transmission system.

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

The Ten-Year Transmission Plan includes critical transmission projects and represents a significant upgrade to APS’s transmission system.

These projects are intended to support growing energy needs, strengthen reliability, and allow for the connection of new resources.

APS is also working to establish and expand advanced grid technologies throughout its service territory to provide long-term benefits both to APS and its customers.

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There have been no recent successful attempts by Congress to pass legislation that would regulate GHG emissions, and it is unclear at this time whether legislation regulating or limiting utility-sector GHG emissions introduced during prior sessions of Congress will become law.

In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is written, enacted, and the specifics of the resulting program are established.

In the event climate change legislation ultimately passes, the actual economic and operational impact of such

legislation on APS depends on a variety of factors, none of which can be fully known until a law is written, enacted, and the specifics of the resulting program are established.

These factors include, without limitation, the terms of the legislation with regard to allowed GHG emissions;

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The California legislature also enacted SB 219, SB 253, and SB 261, which mandate climate-related disclosures for certain companies doing business in California.

CARB is expected to issue regulations for these bills in 2025.

Pinnacle West and APS are currently reviewing whether they would be required to make disclosures pursuant to these bills.

CARB issued proposed regulations for the bills in December 2025, with a proposed deadline of August 10, 2026 for submitting SB 253 reports.

Written comments on the proposal were due on February 9, 2026.

Court of Appeals for the Ninth Circuit granted a motion to enjoin enforcement of SB 261, which requires climate-related financial risk reporting by a January 1, 2026 compliance deadline.

We do not currently believe we would be required to make disclosures pursuant to these bills.

Regulatory Initiatives.

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APS will generally be required to consider the impact of GHG emissions as part of its traditional New Source Review analysis for new major sources and major modifications to existing plants.

EPA’s regulation of carbon dioxide emissions from electric utility power plants has proceeded in fits and starts over most of the last decade.

EPA’s regulation of carbon dioxide emissions f rom electric utility power plants has proceeded in fits and starts over most of the last decade.

Starting on August 3, 2015, EPA finalized the Clean Power Plan, which was the agency’s first effort at such regulation through system-wide generation dispatch shifting.

Those regulations were subsequently repealed by the EPA on June 19, 2019, and replaced by the Affordable Clean Energy (“ACE”) regulations, which were a far narrower set of rules.

Those regulations were subsequently repealed by EPA on June 19, 2019 and replaced by the Affordable Clean Energy regulations, which were a far narrower set of rules.

While the U.S.

Court of Appeals for the D.C.

Circuit subsequently vacated the ACE regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S.

Circuit subsequently vacated the Affordable Clean Energy regulations on January 19, 2021, and ordered a remand for EPA to develop replacement regulations consistent with the original 2015 Clean Power Plan, the U.S.

Supreme Court subsequently reversed that decision on June 30, 2022, holding that the Clean Power Plan exceeded EPA’s authority under the Clean Air Act.

In the final regulations governing power plant carbon dioxide emissions released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants.

In the latest final regulations governing power plant carbon dioxide emissions, released April 25, 2024, EPA issued emission standards and guidelines for various subcategories of new and existing power plants.

Unlike EPA’s Clean Power Plan regulations from 2015, which took a broad, system-wide approach to regulating carbon emissions from electric utility fossil-fuel burning power plants, these new federal regulations are limited to measures that can be installed at individual power plants to limit planet-warming carbon-dioxide emissions.

As such, for new natural gas-fired combustion turbine power plants, EPA is proposing that carbon emission performance standards apply based on the annual capacity factors.

For the highest utilization combustion turbines, EPA is therefore proposing that such facilities be retrofitted for carbon capture and sequestration or utilization controls (“CCS”) by 2032.

For intermediate or low-load natural gas fired combustion turbines, those with 40% or less capacity factors, EPA’s regulations would not require add-on pollution controls.

Instead, natural gas-fired combustion turbines with capacity factors of up to 20% would be effectively unregulated, while such turbines with capacity factors over 20% and up to 40% would be subject to carbon dioxide emission rate limitations.

EPA did not finalize standards for existing natural gas-

fired combustion turbines but has indicated that it will propose a new set of standards, initiating a separate rulemaking, for these existing gas-fired power plants within the next year.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA has finalized subcategories based on planned retirement dates.

This means that facilities retiring before 2032 are effectively exempt from regulation, those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030, and those that retire in 2039 or later must install CCS controls by 2032.

Under current rules, carbon emission performance standards apply based on the annual capacity factors for new natural gas-fired combustion turbine power plants.

The highest utilization combustion turbines must be retrofitted for CCS by 2032.

Intermediate or low-load natural gas fired combustion turbines with 40% or less capacity factors do not require add-on pollution controls.

Instead, natural gas-fired combustion turbines with capacity factors of up to 20% are effectively unregulated, while turbines with capacity factors over 20% and up to 40% are subject to carbon dioxide emission rate limitations.

For coal-fired power plants, instead of imposing regulations based on capacity and utilization, EPA finalized subcategories based on planned retirement dates.

Facilities retiring before 2032 are effectively exempt from regulation;

those that retire between 2032 and 2038 must co-fire with natural gas starting in 2030;

and those that retire in 2039 or later must install CCS controls by 2032.

As of May 10, 2024, several states, electric utility companies, affiliated trade associations, and other entities filed petitions for review of these regulations in the D.C.

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APS is participating in that litigation as part of an ad hoc coalition of electric utility companies, independent power producers, and trade groups, called Electric Generators for a Sensible Transition.

We cannot predict the outcome of the litigation challenging EPA’s latest carbon emission standards for power plants.

In addition, the Trump administration has stated that it intends to reverse or substantially revise these standards.

On February 5, 2025, EPA filed an unopposed motion requesting that the D.C.

Circuit Court of Appeals hold the GHG regulations case in abeyance for 60 days and withhold issuing an opinion while the new leadership at EPA evaluates the rule and determines how it wishes to proceed.

On February 19, 2025, the Court granted EPA’s motion.

EPA subsequently filed a second motion asking the Court to keep the GHG regulations case in abeyance for an indefinite period of time given EPA’s anticipated reconsideration of the rules, with EPA providing status reports every 90 days.

Circuit granted EPA’s motion for an indefinite abeyance on April 25, 2025.

We cannot predict the outcome of the litigation challenging EPA’s current carbon emission standards for power plants.

If the current regulations were to remain in effect, they would likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants.

The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install CCS and achieve 90% capture efficiency may not be feasible.

Future resource plans and procurement efforts implicating the development of such new generation remain pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s existing GHG regulations for power plants.

On June 11, 2025, EPA put forth a proposed rule with two scenarios for repealing the GHG regulations finalized in 2024.

EPA’s primary proposal entails a full repeal of the GHG regulations based on a finding that GHG emissions from fossil fuel-fired power plants do not present a “significant contribution” to dangerous air pollution, thereby eliminating the 2024 GHG power plant regulations in their entirety.

Under EPA’s alternative proposal, only certain portions of the 2024 GHG regulations would be repealed based on a finding that they are unlawful, including the section 111(d) emission guidelines for existing fossil fuel-fired steam generating units (coal-fired power plants), the CCS-based standards for coal-fired steam generating units undertaking a large modification, and the CCS-based standards for new base-load stationary combustion turbines (i.e., those operating at greater than 40% annual capacity factors).

This targeted approach would eliminate the CCS and natural gas co-firing technology-based pollution limits that would apply to both existing coal-fired power plants and new gas-fired combustion turbine power plants.

However, efficiency-based standards for new combustion turbines would remain in place under this alternative proposal.

EPA’s proposed rule to repeal the 2024 GHG regulations was published in the Federal Register on June 17, 2025.

Comments were due by August 7, 2025.

We cannot predict the outcome of future rulemaking or other regulatory proceedings aimed at changing or eliminating the current EPA emission standards for power plants.

If this regulation remains in effect, it will likely lead to a material increase in APS’s costs to build, operate, and maintain new, frequently operated gas-fired power plants.

The regulatory deadlines in 2032 by which new, frequently operated gas-fired power plants must install carbon capture and sequestration and achieve 90% capture efficiency may not be feasible.

Future resource plans and procurement efforts implicating the development of such new generation remains pending and, as such, at this time APS is not able to quantify the financial impact associated with EPA’s GHG regulations for power plants.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standards (“NAAQS”) and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.

Further changes to these regulations may also face judicial review.

APS cannot predict the outcome of any such litigation.

On February 18, 2026, EPA’s repeal of the 2009 “Endangerment Finding” was finalized and published in the Federal Register.

This action is expected to provide legal and regulatory support for EPA’s pending proposals seeking to eliminate or significantly limit the scope of the current EPA carbon emission standards and guidelines for new and existing power plants .

The repeal of the “Endangerment Finding” is subject to judicial review, with lawsuits being filed on February 18, 2026 in the D.C.

Circuit Court of Appeals seeking to challenge the repeal.

We cannot the predict the outcome of such litigation.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone NAAQS and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.

The financial impact of complying with current and future environmental rules could jeopardize the economic viability of APS’s fossil-fuel powered plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.

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

Sustainability Reporting

APS prepares an annual inventory of GHG emissions from its operations.

For APS’s operations involving fossil-fuel electricity generation and electricity transmission and distribution, APS’s annual GHG inventory is reported to EPA under the EPA GHG Reporting Program.

In addition to reporting to EPA, we publicly report Scope 1 and 2 GHG emissions.

This performance data is then communicated to the public in Pinnacle West’s annual Corporate Responsibility Report and is available on our website ( www.pinnaclewest.com/corporate-responsibility ).

The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance.

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

EPA Environmental Regulation

Coal Combustion Waste.

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash.

On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCRs, such as fly ash and bottom ash.

The rule regulates CCR as a non-hazardous waste under Subtitle D of the RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions.

These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.

The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity.

Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below.

Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments and are the subject of the regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal.

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The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

• Following the passage of the Water Infrastructure Improvements for the Nation (“WIIN”) Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands.

At this time, the Arizona Department of Environmental Quality (“ADEQ”) has taken steps to develop a CCR permitting program.

It remains unclear when the EPA would approve the permitting program pursuant to the WIIN Act.

• Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to either authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands.

ADEQ has taken steps to develop a CCR permitting program and proposed state regulations governing CCR permitting in the summer of 2024.

On April 1, 2025, the Arizona Governor’s Regulatory Review Council approved ADEQ’s proposed rulemaking governing CCR permitting.

ADEQ will submit an approval package to EPA, which will have to approve the entire state program before it is operational.

It remains unclear when EPA would approve that permitting program pursuant to the Water Infrastructure Improvements for the Nation Act.

On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits, which would impact facilities like Four Corners located on the Navajo Nation.

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Apart from a subsequent proposal issued on August 14, 2019 to add a specific health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

• With respect to APS’s Cholla facility, APS’s application for alternative closure was submitted to EPA on November 30, 2020.

While EPA has deemed APS’s application administratively “complete,” the Agency’s approval remains pending.

If granted, this application would allow the continued disposal of CCR within Cholla’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025.

This application will be subject to public comment and, potentially, judicial review.

We expect to have a proposed decision from EPA regarding Cholla in 2025 .

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending.

We cannot predict the outcome of these regulatory proceedings or when EPA will take final action on those matters that are still pending.

Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

On April 25, 2024, EPA took final action on a proposal to expand the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015.

This new class of CCR management units (“CCRMUs”), which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCR would have been placed on land.

This new class of CCRMUs, which contain at least 1,000 tons of CCR, broadly encompass any location at an operating coal-fired power plant where CCRs would have been placed on land.

As proposed, this would include not only historically closed landfills and surface impoundments but also prior applications of CCR beneficial use (with exceptions for historical roadbed and embankment applications).

Existing CCR regulatory requirements for groundwater monitoring, corrective action, closure, post-closure care, and other requirements will be imposed on such CCRMUs.

At this time, APS is still evaluating the impacts of this final regulation on its business, with initial CCRMU site surveys due to be completed by February 2026 and final site investigation reports to be finalized by February 2027.

Based on the information available to APS at this time, APS cannot reasonably estimate the fair value of the entire CCRMU asset retirement obligation.

Depending on the outcome of those evaluations and site

investigations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners.

Under EPA’s legacy 2024 CCRMU rule, initial CCRMU site surveys originally due to be completed by February 2026 and final site investigation reports by February 2027.

On February 10, 2026, EPA published a final rule extending multiple compliance deadlines applicable to CCRMUs established under the prior rule.

The final rule extends the deadline for completing Parts One and Two of Facility Evaluation Reports by one year to February 2027 and February 2028, respectively.

EPA also extended associated compliance deadlines for groundwater monitoring and certain

closure requirements.

On February 9, 2026, EPA sent to the Office of Management and Budget for review a rule proposal that is anticipated to provide more substantive changes to certain aspects of the legacy 2024 CCRMU rule.

APS is still in the process of evaluating the impacts of these CCRMU regulations on its business and cannot predict the outcome of any future rulemaking or other regulatory proceedings aimed at changing the current EPA CCRMU rules.

Based on the information available to APS at this time, APS cannot reasonably estimate the cost of the entire CCRMU asset retirement obligation.

Depending on the outcome of the pending legacy 2024 CCRMU rule amendments and APS’s evaluations, the costs associated with APS’s management of CCR could materially increase, which could affect our financial condition, results of operations, or cash flows.

APS currently disposes of CCR in ash ponds and dry storage areas at Four Corners.

The Navajo Plant disposed of CCR only in a dry landfill storage area.

The Cholla Plant disposed of CCR in ash ponds and dry storage areas prior to ceasing coal-fired operations.

Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

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APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action.

In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units subject to alternative closure).

In addition, under the current regulations, all such dispo sal units must have ceased operating and initiated closure as of April 11, 2021 (except for those disposal units at Cholla that had been subject to alternative closure, which initiated closure work on June 30, 2025).

APS completed the assessments of corrective measures on June 14, 2019;

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In addition, APS has also solicited input from the public and hosted public hearings as part of this process.

APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations.

APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations, and Removal Costs within Regulatory Liabilities.

As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change.

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Effluent Limitation Guidelines .

EPA published effluent limitation guidelines (“ELG”) on October 13, 2020, and based off those guidelines, APS completed a National Pollutant Discharge Elimination System (“NPDES”) permit modification for Four Corners on December 1, 2023.

EPA published ELGs on October 13, 2020, and, based off those guidelines, APS completed a NPDES permit modification for Four Corners on December 1, 2023.

The ELG standards finalized in October 2020 relaxed the “zero discharge” standard for bottom ash transport waters EPA finalized in September 2015.

However, on April 25, 2024, EPA finalized new ELG regulations that once again require “zero discharge” standards for flows of bottom ash transport water at power plants like Four Corners.

Nonetheless, for power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards.

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

For power plants that permanently cease operations by December 31, 2034, such facilities can continue to comply with the 2020 ELG standards.

On December 31, 2025, EPA published a final rule extending by five years the compliance deadlines for achieving the 2024 zero-discharge standards for bottom ash transport wastewater from year-end 2029 to year-end 2034, among other changes to the previous rules.

EPA is also collecting additional information on zero-discharge technologies, including cost and performance data, to inform future potential rulemakings to modify or relax the current zero-discharge ELG standards.

We cannot predict the

outcome of any future rulemaking or other regulatory proceedings aimed at modifying the current ELG standards.

Ozone National Ambient Air Quality Standards.

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Further, on December 23, 2020, EPA issued a final regulation retaining the current primary NAAQS for ozone, following a required scientific review process.

With ozone standards becoming more stringent, our fossil generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas.

With ozone standards becoming more stringent, our fossil generation units will come under increasing pressure to reduce emissions of nitrogen oxide (“NOx”) and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas.

EPA was expected to designate attainment and nonattainment areas relative to the new 70 ppb standard by October 1, 2017.

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The vast majority of APS’s natural gas-fired EGUs are located in these jurisdictions.

Areas of Arizona and the Navajo Nation where the remainder of APS’s fossil-fuel fired EGU fleet is located were designated as in attainment.

At this time, because proposed SIPs and FIPs implementing the revised ozone NAAQSs have yet to be released, APS is unable to predict what impact the adoption of these standards may have on APS.

APS will continue to monitor these standards as they are implemented within the jurisdictions affecting APS.

Areas of Arizona and the Navajo Nation where the remainder of APS’s fossil-fuel fired electric generating unit fleet is located were designated as in attainment.

O n October 7, 2022, EPA took final action designating Maricopa County, which includes the Phoenix, Arizona metropolitan area, as “moderate” for non-attainment with the governing ozone NAAQS, which provided for an August 3, 2024 attainment “deadline” by which the area would be automatically designated as in “serious” non-attainment unless it achieved the 2015 ozone NAAQS.

At this time, an EPA proposal (dated November 19, 2025) is pending that finds Maricopa County would have attained compliance with the 2015 ozone NAAQS by the “moderate” non-attainment deadline but for emissions emanating from outside the United States.

If finalized as proposed, this action would maintain the current non-attainment status for Maricopa County without implicating more stringent emissions limitations for this area, among other requirements.

At this time, APS is unable to predict the outcome of this proceeding, including whether the November 19, 2025 proposal will be adopted by EPA.

If finalized, this proposal is also subject to judicial review.

APS will continue to monitor these standards as they are implemented within the jurisdictions affecting the Company’s operations.

EPA Good Neighbor Proposal for Arizona .

On March 15, 2023, EPA issued its final Good Neighbor Plan for 23 states in order to ensure that the cross-state transport of ozone forming emissions does not interfere with downwind state compliance with the National Ambient Air Quality Standards (“NAAQS”).

Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide (“NOx”) emissions.

Thermal power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for NOx emissions.

While Arizona was not among the 23 states subject to EPA’s March 2023 final action, EPA announced on January 23, 2024, that it was proposing to add Arizona and New Mexico (along with two other additional states) to EPA’s NOx emission allowance trading program finalized last year.

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In addition, on December 19, 2024, EPA announced that it was withdrawing its proposal to add Arizona (along with other western states) to the federal Good Neighbor Plan.

As such, while EPA may elect to resume work on and finalize this proposal in the future, it is unlikely to do so over a near-term horizon.

APS cannot predict the outcome of any future EPA efforts to add Arizona to the federal Good Neighbor Plan (which depends on action disapproving the Arizona State Implementation Plan) or whether the Good Neighbor Plan itself will remain in effect pending the outcome of judicial review in the D.C.

Circuit Court of Appeals.

Should the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load.

On March 12, 2025, EPA announced its intention to reconsider the Good Neighbor Plan and on January 30, 2026, EPA published a proposed rule in the Federal Register that would approve Arizona’s and New Mexico’s State Implementation Plans concerning the cross-state transport of

ozone forming emissions.

Such approval, if finalized as proposed, would remove APS’s operations in Arizona and New Mexico from the scope of future efforts to regulate such emissions.

APS cannot predict the outcome of this pending regulatory action nor when EPA may take final action on this proposal.

If finalized as proposed, this action would then be subject to judicial review and APS cannot predict the outcome of such litigation, if any arises.

In addition, APS cannot predict the outcome of any future EPA efforts to add Arizona or New Mexico to a future federal program addressing the cross-state transport of ozone-forming emissions.

Should a federal program like the Good Neighbor Plan ultimately be imposed on APS and its operations in Arizona and New Mexico, it would have material impact on both the costs to operate current APS power plants and APS’s ability to develop new thermal generation to serve load.

At this time, APS cannot predict the impact on the Company’s financial condition, results of operations, or cash flows.

Revised Mercury and Air Toxics Standard (“MATS”) Proposal.

On April 25, 2024, EPA finalized revisions to the existing MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants.

The final regulations increase the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and require the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing).

These final regulations will take effect for existing coal-fired power plants, such as Four Corners, within three years of publication in the Federal Register.

Based on APS’s assessment of the revised MATS regulations, this final rule is unlikely to have a material impact on plant operations or require significant capital expenditures to ensure compliance.

On February 20, 2026, EPA issued a final rule repealing the 2024 revisions to MATS regulations governing emissions of toxic air pollution from existing coal-fired power plants.

The repeal of the 2024 amendment means that MATS regulations revert to the pre-existing framework for MATS emission limits established in 2012.

As a result, the 2024 revisions that would have increased the stringency of filterable particulate matter limits used to demonstrate compliance with MATS and required the use of continuous emissions monitoring systems to ensure compliance (as opposed to periodic performance testing) will not take effect for existing coal-fired power plants, such as Four Corners.

Superfund-Related Matters.

The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.

CERCLA establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.

Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”).

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APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.

In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”).

In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and man agement of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”).

The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022.

EPA notified APS that the RI/FS was approved on September 11, 2024.

APS’s estimated costs related to this investigation and study is approximately $3 million .

APS anticipates incurring additional expenditures in the future, but

because the final costs associated with remediation requirements set forth in the RI/FS are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

In connection with APS’s status as a PRP for OU3, since 2013 APS and at least two dozen other parties have been defendants in various CERCLA lawsuits stemming from allegations that contamination from OU3 and elsewhere has impacted groundwater wells operated by the Roosevelt Irrigation District (“RID”).

On September 25, 2025, EPA executed a final ROD adopting the OU3 remedies proposed in the approved RI/FS OU3.

APS’s expenditures related to this investigation and study are approximately $3 million .

APS anticipates it may incur additional expenditures in the future, but because the final costs associated with remediation requirements set forth in the RI/FS and ROD are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated;

however, APS does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

At this time, only one active lawsuit remains pending in the U.S.

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On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona.

In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site.

The SIBW Superfund site includes the APS Ocotillo power plant site.

In particular, EPA seeks information from

APS regarding APS’s use, storage, and disposal of substances containing PFAS at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash Superfund site.

The South Indian Bend Wash Superfund site includes the APS Ocotillo power plant site.

APS filed its response to this information request on April 29, 2022.

On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years.

On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the South Indian Bend Wash site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years.

APS estimates that its costs to oversee and participate in the remedial investigation work will be approximately $1.7 million.

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The latest NPDES permit for Four Corners was issued on September 30, 2019.

Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board (“EAB”) took up review of the Four Corners NPDES Permit.

The EAB denied the environmental group petition on September 30, 2020.

While on January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S.

Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board up review of the Four Corners NPDES Permit.

The Environmental Appeals Board denied the environmental group petition on September 30, 2020.

While on January 22, 2021, the environmental groups filed a petition for review of the Environmental Appeals Board’s decision with the U.S.

Court of Appeals for the Ninth Circuit, the parties to the litigation (including APS) finalized a settlement on May 2, 2022.

This settlement requires investigation of thermal wastewater discharges from Four Corners, administratively closes the litigation filed in January of 2021, and APS does not expect the outcome to have a material impact on its financial condition, results of operations, or cash flows.

This settlement required investigation of thermal wastewater discharges from Four Corners over an extended period of time while administratively closing the litigation filed in January of 2021 during the pendency of the investigation.

Having completed the investigation in accordance with the settlement, the Ninth Circuit Court of Appeals granted a motion to dismiss the litigation on October 3, 2025.

In addition, as of October 9, 2025, EPA deemed APS’s application for a renewal NPDES Permit for Four Corners to be administratively complete.

APS cannot predict the timing or outcome of EPA’s evaluation of this pending renewal application.

Based on a declaration from the U.S.

Bureau of Reclamation, as of January 1, 2026, Arizona’s supply of Colorado River water will remain subject to a Tier 1 shortage.

This is the third year since 2022 that a Tier 1 shortage has been declared.

This is the fourth year since 2022 that a Tier 1 shortage has been declared.

The most severe shortage to have been declared was a Tier 2a shortage in 2023.

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An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

In addition, APS is a party to a water contract that allows the Company to secure water for Four Corners in the event of a water shortage in the San Juan River Basin.

Gila River Adjudication.

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Further proceedings have been initiated to determine the specific hydro-geologic testing protocols for subflow depletion determinations.

The determinations made in this final stage of the proceedings may ultimately govern the adjudication of rights for parties, such as APS, that rely on groundwater extraction to support their industrial operations.

The determinations made in this final stage of the proceedings may ultimately govern the adjudication of rights for parties, such as APS, which rely on groundwater extraction to support their industrial operations.

APS cannot predict the outcome of these proceedings.

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The adjudication court is currently conducting a trial of federal reserved water right claims asserted by the Hopi Tribe and by the United States as trustee for the Tribe.

In addition, the adjudication court has established a schedule for consideration of separate federal reserved water right claims asserted by the Navajo Nation and by the United States as trustee for the Nation.

In addition, the adjudication court has established a schedule for consideration of separate federal reserved water right claims asserted by the

Navajo Nation and by the United States as trustee for the Nation.

There is no established timeframe within which the adjudication court is expected to issue a final determination of water rights for the Hopi Tribe and the Navajo Nation, and any such final determination is likely to occur multiple years in the future.

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Key human capital measures and objectives that drive our business strategy include employee safety, employee development, strong company culture based upon the APS Promise, strong talent pipelines, extensive learning and development focus, and succession planning.

The below table presents the employee count as of December 31, 2024:

The table below presents the employee count as of December 31, 2025:

Principal Executive Office

Address Year of

Formation Approximate

December 31, 2024

Formation Approximate Number

of Employees at December 31, 2025

Pinnacle West 400 North Fifth Street

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On August 23, 2024, 27 IT Communications Field Specialists joined the existing bargaining unit represented by IBEW.

Collective bargaining relating to these employees is ongoing.

APS and IBEW Local 387 continue to bargain in good faith to reach an agreement with the IT Communications Field Specialist group.

Additionally, IBEW Local 387, in accordance with the CBA, has provided APS with a 60-day notice of request to bargain, as the amendable date of the current CBA is April 1, 2026.

Culture and Engagement

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It represents the opportunity to build on our cultural strengths and develop new behaviors to enable our future success.

In 2025, we refreshed our Promise to ensure its relevancy and alignment with our strategic direction.

We updated our Mission to ensure alignment with our top priorities—safety, reliability, and affordability.

We also updated some of our shared behaviors to make sure they reflect who we are as a company and how we will succeed today and into the future.

The APS Promise continues to be reinforced and integrated throughout our Company programs and messaging.

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We believe that belonging matters.

We recognize that differences of identities, perspectives, and experiences is a key driver for our success.

We recognize that differences of identities, perspectives, and experiences are a key driver for our success.

Inclusion at the Company involves embracing the unique perspectives of each employee.

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• Support for 11 employee networking groups to encourage employees to develop themselves, advance in their chosen field, and join a community;

• Executive listening sessions to provide employees with opportunities to be heard;

• An optional self-paced module available to all employees that explains how cultural competence drives inclusion.

• Continuous listening practices to provide employees with opportunities to be heard.

Employee Safety

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• Commitment to Growth and Development :

We provide a wide range of professional development opportunities, including leadership academies, rotational programs, mentoring, industry certifications, and loaned executive programs.

In 2024, we ran dedicated programs for individual contributors, new leaders, and high potential managers.

We also launched an enterprise-wide on-demand learning platform to support a modern learning culture, with over 2,220 active users, encompassing engagement from every business unit and 5,650 hours of learning in 2024.

We provide a wide range of professional development opportunities to support a modern learning culture, including on-demand learning, learning events, leadership academies, rotational programs, mentoring, industry certifications, and loaned executive programs.

We also run dedicated programs for individual contributors, new leaders, and high-potential managers.

• Robust Talent Pipelines :

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We achieve this through an array of programs, including craft apprenticeships, engineering and rotational programs, and internships.

We partner closely with educational institutions and organizations to build a talent-ready pool for these critical roles.

• Strategic Partnerships :

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• Innovation in Talent Acquisition :

Palo Verde expanded its internship programs in 2024 to include nuclear operations, further strengthening our talent pipeline for the critically important licensed and non-licensed operators.

In recent years, APS has expanded its internship programs to include interns in APS’s Forestry and Water Resource Departments, and Palo Verde expanded its programs to include nuclear operations.

• Leadership and Talent Philosophy .

In 2025, APS introduced a new Leadership Model and Talent Philosophy to provide clarity and focus on how our leaders can shape a culture where people and performance excel.

APS’s Leadership Model outlines key traits and skills that

bring APS’s Promise to life with actionable behaviors at each leadership level.

APS’s Talent Philosophy provides guidance for leaders to define a shared set of standards as it relates to managing talent.

These standards are focused on Behaviors, Transparency, Differentiation, Leadership Commitment and Performance to ensure consistency, reduce biases, and align leadership.

These initiatives contribute to a high-performing and engaged workforce that supports the long-term success of our Company.

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We also evaluate leadership potential through assessments, performance reviews, and 360-degree feedback.

The addition of our Leadership Model will also serve as guidance to help us identify and develop talent throughout our leadership pipeline, ensuring we use the same standards throughout the enterprise.

We collaborate with senior leadership to build a pipeline of qualified internal and external candidates and continuously adapt our succession planning process to meet evolving business needs and industry trends.

Total Rewards Strategy

Recognizing that our employees are among our most valuable assets, we have developed a comprehensive Total Rewards strategy to attract, engage, and retain a high-performing workforce.

Recognizing that our employees are the foundation of our innovation, growth, and success, we have developed a comprehensive Total Rewards strategy to attract, engage, and retain a high-performing workforce.

Our Total Rewards program encompasses a comprehensive suite of offerings, including competitive compensation, a robust benefits package, retirement savings plans, professional development opportunities, recognition programs, and a focus on employee well-being.

This holistic approach aims to (1) attract and retain top talent by offering a competitive and attractive compensation and benefits package, (2) support employee well-being by promoting a healthy work-life balance and providing resources to support employee physical, mental, and financial well-being, (3) foster employee engagement and motivation through recognition programs, professional development opportunities, and a strong emphasis on career growth, and (4) enhance employee satisfaction by creating a rewarding and fulfilling work experience for all employees.

This holistic approach aims to (1) attract and retain top talent by offering a competitive and attractive compensation and benefits package, (2) support employee well-being by promoting a healthy lifestyle, work-life balance and providing resources to support employee physical, mental, and financial well-being, (3) foster employee engagement and motivation through recognition programs, professional development opportunities, and a strong emphasis on career growth, and (4) enhance employee satisfaction by creating a rewarding and fulfilling work experience for all employees.

We continuously evaluate and refine our Total Rewards program to ensure it remains competitive, relevant, and responsive to the evolving needs and expectations of our employees.

BUSINESS OF 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 Delaware limited liability corporation and 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.

DOE’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.

states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the TransCanyon partners’ utility affiliates.

These opportunities include the proposed 500-kV Cross-Tie

transmission project, 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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Nobles 2 achieved commercial operation in December 2020.

Both wind farms deliver power under long-term power purchase agreements (“PPAs”).

Both wind farms deliver power under long-term PPAs.

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

El Dorado is an Arizona corporation and 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 and holds 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.

• $25 million investment in AZ-VC Fund I, LLC (formerly invisionAZ Fund) (“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.

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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 Advanced Power Solutions, Inc.

(“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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We use our website ( www.pinnaclewest.com ) as a channel of distribution for material Company information.

The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”):

The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC:

Annual Reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports.

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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 1. Business