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Energy Sources and Resource Planning

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:

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

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peers. 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; promoting customer technology and energy efficiency; and optimizing regional resources.

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.

Generation Facilities

APS has ownership interests in or leases the nuclear, gas, oil, coal, and solar generating facilities as well as energy storage facilities described below. For additional information regarding these facilities, see Item 2.

Nuclear

Palo Verde Generating Station — Palo Verde is a 3-unit nuclear power plant located approximately 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and approximately 23.9% of Unit 2. In addition, APS leases approximately 5.2% of Unit 2, resulting in a 29.1% combined ownership and leasehold interest in that unit. APS has a total entitlement from Palo Verde of 1,146 MW.

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. 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.

Palo Verde Operating Licenses — Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987, and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2, and 3 to June 2045, April 2046, and November 2047, respectively.

Palo Verde Fuel Cycle — The participant owners of Palo Verde are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The fuel cycle for Palo Verde is comprised of the following stages:

•Mining and milling of uranium ore to produce uranium concentrates;

•Conversion of uranium concentrates to uranium hexafluoride;

•Enrichment of uranium hexafluoride;

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•Fabrication of fuel assemblies;

•Utilization of fuel assemblies in reactors; and

•Storage and preparation for disposal of spent nuclear fuel.

The Palo Verde participants have contracted for 100% of Palo Verde’s requirements for uranium concentrates through 2028 and 70% through 2029; 100% of Palo Verde’s requirements for conversion services through 2030 and 32% through 2031; 100% of Palo Verde’s requirements for enrichment services through 2028; and 100% of Palo Verde’s requirements for fuel fabrication through 2027 for Unit 2 and Unit 1 and 2028 for Unit 3.

Spent Nuclear Fuel and Waste Disposal — The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to begin to accept, transport, and dispose of spent nuclear fuel and high-level waste generated by the nation’s nuclear power plants by 1998. The DOE’s obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the “Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. The DOE had planned to meet its NWPA and Standard Contract disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. 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. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). Following the D.C. Circuit’s August 2013 order, the NRC issued two volumes of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. Publication of these volumes does not signal whether or when the NRC might authorize construction of the repository. APS is directly involved in legal proceedings related to the DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high-level waste.

APS Lawsuit for Breach of Standard Contract — In December 2003, APS, acting on behalf of itself and the Palo Verde participants, filed a lawsuit against the DOE in the United States Court of Federal Claims (“Court of Federal Claims”) for damages incurred due to the DOE’s breach of the Standard Contract. The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded damages to APS and the Palo Verde participants for costs incurred through December 2006.

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the United States Court of Federal Claims. The lawsuit sought to recover damages incurred due to DOE’s breach of the Standard Contract for failing to accept Palo Verde’s spent nuclear fuel and high-level waste from January 1, 2007 through June 30, 2011, pursuant to the terms of the Standard Contract and the NWPA. On August 18, 2014, APS and DOE entered into a settlement agreement, which required DOE to pay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, the settlement agreement provided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2025. APS is currently evaluating a proposed extension to the settlement to cover costs paid through December 31, 2028.

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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 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.

Waste Confidence and Continued Storage — On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s waste confidence decision and temporary storage rule (“Waste Confidence Decision”). The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with National Environmental Policy Act. In September 2013, the NRC issued its draft Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed as the Continued Storage Rule, the NRC’s decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continued Storage Rule.

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. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate expanding the ISFSI, or alternative storage solutions that may obviate the need to expand the ISFSI, to accommodate all of the fuel that will be irradiated during the period of extended operation.

Nuclear Decommissioning Costs — APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’s ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge (paid by all retail customers taking service from the APS system). Based on current nuclear decommissioning trust asset balances, site specific decommissioning cost studies, anticipated future contributions to the decommissioning trusts, and return projections on the asset portfolios over the expected remaining operating life of the facility, we are on track to meet the current site-specific decommissioning costs for Palo Verde at the time the units are expected to be decommissioned. 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 14 for a discussion of the insurance maintained for Palo Verde by the Palo Verde participants, including APS.

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Natural Gas and Oil Fueled Generating Facilities

APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near Palo Verde; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; and Yucca, located near Yuma. Several of the units at Yucca run on either gas or oil. APS has two oil-only power plants: Douglas, located in the town of Douglas, Arizona and Yucca GT-4 in Yuma, Arizona. APS owns and operates each of these plants with the exception of one oil-only combustion turbine unit and one oil and gas steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District. APS has a total entitlement from these plants of 3,722 MW. A portion of the gas for these plants is financially hedged up to three years in advance of purchasing and that position is converted to a physical gas purchase one month prior to delivery. APS has long-term gas transportation agreements with three different companies, some of which are effective through 2052. 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 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

Four Corners — Four Corners is located in the northwestern corner of New Mexico and was originally a 5-unit coal-fired power plant. APS owns 100% of Units 1, 2 and 3, which were retired as of December 30, 2013. APS operates the plant and owns 63% of Four Corners Units 4 and 5. APS has a total entitlement from Four Corners of 970 MW.

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. The Four Corners co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016 through 2031, which was amended and restated on July 1, 2024.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also required the approval of the DOI, as did a related federal rights-of-way grant. A federal environmental review was undertaken as part of the DOI review process and culminated in the issuance by DOI of a record of decision on July 17, 2015, justifying the agency action to extend the life of the plant and the adjacent mine.

In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners as early as fall 2023. In July 2024, APS and the owners amended the agreement to retain the option for seasonal operation. Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring. The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages. As of the date of this report, APS has elected not to begin seasonal operation due to market conditions.

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Cholla — Cholla was originally a 4-unit coal-fired power plant, which is located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4, and APS operated that unit for PacifiCorp. On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. 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 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 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. 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.

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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. Capacity amounts are approximate.

LocationActual/Target

Commercial

Operation

DateNet Capacity (MW) In OperationNet Capacity (MW)

Planned/Under

Development

Solar:

PalomaGila Bend, AZ201117

Cotton CenterGila Bend, AZ201117

Hyder IHyder, AZ201217

Chino ValleyChino Valley, AZ201220

Hyder IIHyder, AZ201314

FoothillsYuma, AZ201338

Gila BendGila Bend, AZ201436

Luke AFBGlendale, AZ201511

Desert StarBuckeye, AZ201510

Red RockRed Rock, AZ201644

Agave SolarArlington, AZ2023150

Ironwood SolarDateland, AZ(a)168

Multiple FacilitiesAZVarious4

Distributed Energy: (b)

APS Owned (c)AZVarious41

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.

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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.

LocationActual/Target

Commercial

Operation

DateNet Capacity (MW) In OperationNet Capacity (MW)

Planned/Under

Development

BESS:

PalomaGila Bend, AZ202317

Cotton CenterGila Bend, AZ202317

Hyder IHyder, AZ202316

Chino Valley (a)Chino Valley, AZ202319

Hyder IIHyder, AZ202314

FoothillsYuma, AZ202335

Gila BendGila Bend, AZ202332

Desert StarBuckeye, AZ202210

Red Rock (a)Red Rock, AZ202341

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. See Note 13. APS continually assesses its need for additional capacity resources to ensure system reliability.

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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 AgreementMay 1 through April 30, 2021-2025463

Extension Term May 1 through October 31, 2025-2032525

Tolling AgreementJune 1 through September 30, 2020-2025565

First Extension Term May 1 through October 31, 2026575

Second Extension TermMay 1 through October 31, 2027-2038600

Tolling AgreementJune 1 through September 30, 2020-2026570

Extension Term May 1 through October 31, 2027-2034600

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.

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LocationActual/ Target

Commercial

Operation DateTerm

(Years)Net Capacity

(MW)

In OperationNet Capacity

(MW)

Planned/Under Development

PPAs

Solar:

SolanaGila Bend, AZ201330 250

RE AjoAjo, AZ201125 5

Sun E AZ 1Prescott, AZ201130 10

Saddle MountainTonopah, AZ201230 15

BadgerTonopah, AZ201330 15

GillespieMaricopa County, AZ201330 15

Mesquite Solar 5Tonopah, AZ202320 60

Sunstreams 3Arlington, AZ202420 215

Yuma Solar EnergyYuma County, AZ202520 70

Harquahala Sun 2Tonopah, AZ202520 300

Sunstreams 4Arlington, AZ202520 300

Serrano SolarPima & Pinal County, AZ202520 170

CO Bar Solar CCoconino County, AZ202720 206

Hashknife 1Navajo County, AZ202620 275

CatclawBuckeye, AZ202620 225

Papago SolarMaricopa County, AZ202620 150

Hashknife 2Navajo County, AZ202720 200

KittEloy, AZ202620 100

PioneerYuma, AZ202720 300

Maricopa Energy Center Phase 1Maricopa County, AZ202620 183

Maricopa Energy Center Phase 2Maricopa County, AZ202720 367

Snowflake SolarSnowflake, AZ202720 475

Wind:

Aragonne MesaSanta Rosa, NM202220 200

High LonesomeMountainair, NM200930 100

Perrin Ranch WindWilliams, AZ201225 99

Chevelon ButteWinslow, AZ202320 238

Chevelon Butte IIWinslow, AZ202420 216

West Camp Wind FarmNavajo County, AZ202620 500

Geothermal:

Salton SeaImperial County, CA200623 10

Biomass:

SnowflakeSnowflake, AZ200825 14

Biogas:

NW Regional LandfillSurprise, AZ201220 3

Total PPAs 2,305 2,981

Distributed Energy (a)

Solar

Third-party OwnedAZVarious 1,773 82

Agreement 1Bagdad, AZ201125 15

Agreement 2AZ2011-201220-2118

Total Distributed Energy 1,806 82

Total 4,111 3,063

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

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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

Commercial

Operation Date
Term

(Years)Nameplate

Capacity (MW)

In OperationNameplate Capacity

(MW)

Planned/Under Development

BESS PPAs

Mesquite 5Tonopah, AZ202320 60

West Wing 1Peoria, AZ202420 80

El SolPhoenix, AZ202420 50

Sun Streams 3Arlington, AZ202420 215

YumaYuma, AZ202520 67

Westwing 2Peoria, AZ202520 120

Harquahala Sun 2Quartzsite, AZ202520 300

Scatterwash 1Phoenix, AZ202520 170

Pluto BESSGoodyear, AZ202520 75

PapagoTonopah, AZ202520 300

Scatterwash 2Phoenix, AZ202520 85

SerannoPima County, AZ202520 214

Sun Streams 4Arlington, AZ202520 300

Justice Buckeye, AZ202620 150

CatclawBuckeye, AZ202620 250

Hashknife 1Navajo County, AZ202620 275

Beehive Peoria, AZ202620 250

Desert BloomPeoria, AZ202620 150

Maricopa Energy Center Phase 1Maricopa County, AZ202620 183

Maricopa Energy Center Phase 2Maricopa County, AZ202620 367

KittEloy, AZ202620 100

White TankAvondale, AZ202720 100

PioneerYuma, AZ202720 300

Co Bar CCoconino County, AZ202720 206

Hashknife 2Navajo County, AZ202720 200

Harquahala FlatsTonopah, AZ202720 225

Snowflake PVSSnowflake, AZ202720 475

Harquahala Flats 2Tonopah, AZ202720 225

Total BESS PPAs 2,036 3,456

Distributed BESS

Third-party OwnedAZVarious 103 37

Total 2,139 3,493

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Current and Future Resources

Current Demand and Reserve Margin

Electric power demand is generally seasonal. In Arizona, demand for power peaks during the hot summer months. 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. APS carries

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

performance. 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 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 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. 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 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 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 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.

Competitive Environment and Regulatory Oversight

Retail

The ACC regulates APS’s retail electric rates and its issuance of securities. The ACC must also approve any significant transfer or encumbrance of APS’s property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS, and their respective affiliates. See Note 8 for information regarding ACC’s regulation of APS’s retail electric rates.

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

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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. 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.

Wholesale

FERC regulates rates for wholesale power sales and transmission services. See Note 8 for information regarding APS’s transmission rates. During 2025, approximately 4.5% of APS’s electric operating revenues resulted from such sales and services. APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS hedges both electricity and natural gas. The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

Transmission and Delivery

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 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 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. APS is strategically deploying a variety of technologies that are intended to allow customers to better manage their energy usage, minimize system outage durations and frequency, enable customer choice for new customer sited technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain delivery functions.

Environmental Matters

Climate Change

Legislative Initiatives. 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

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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; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted.

In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation regulating GHGs, the California legislature enacted AB 32 and Senate Bill (“SB”) 1368 in 2006 to address GHG emissions. In October 2011, the California Air Resources Board (“CARB”) approved final regulations that established a state-wide cap on GHG emissions beginning on January 1, 2013, and established a GHG allowance trading program under that cap. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA.

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 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. The U.S. 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. In 2009, EPA determined that GHG emissions endanger public health and welfare. As a result of this “Endangerment Finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. 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. 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 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 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 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.

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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. Circuit Court of Appeals. 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. 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. The D.C. 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.

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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. 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. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement but cannot predict whether it would obtain such recovery.

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 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

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

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

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

•On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

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 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. 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

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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. As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure 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; however, additional investigations and engineering analyses that will support the remedy selection are still underway. 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, 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. Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, we cannot predict any ultimate impacts to APS; however, at this time APS does not believe that any potential changes to the cost estimate from the CCR rule’s corrective action assessment process for Four Corners or Cholla would have a material impact on its financial condition, results of operations, or cash flows.

Effluent Limitation Guidelines. 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. 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, and cash flows.

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

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

Ozone National Ambient Air Quality Standards. On October 1, 2015, EPA finalized revisions to the primary ground-level ozone NAAQS at a level of 70 parts per billion (“ppb”). 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 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. While EPA took action designating attainment and unclassifiable areas on November 6, 2017, the Agency’s final action designating non-attainment areas was not issued until April 30, 2018. At that time, EPA designated the geographic areas containing Yuma and Phoenix, Arizona as in non-attainment with the 2015 70 ppb ozone NAAQS. 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 electric generating unit fleet is located were designated as in attainment. On 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 NAAQS. 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. That proposal involves adding these states to the Good Neighbor Plan and disapproving the corresponding provisions of each state’s State Implementation Plan. Because APS operates thermal power plants within Arizona and those portions of the Navajo Nation within New Mexico, APS’s power plants would be subject to EPA’s Good Neighbor Plan upon finalization of this proposal. EPA’s final Good Neighbor Plan is subject to ongoing judicial review in the D.C. Circuit Court of Appeals. On June 27, 2024, the U.S. Supreme Court granted a motion to stay the effectiveness of EPA’s final Good Neighbor Plan pending the resolution of the litigation. As such, APS will not be impacted by the Good Neighbor Plan until the outcome of this litigation is finalized. 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. 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

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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 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. CERCLA establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (each a “PRP”). PRPs may be strictly, jointly, and severally liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”), in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). The RI/FS for OU3 was finalized and submitted to EPA at the end of 2022. EPA notified APS that the RI/FS was approved on September 11, 2024. 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.

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. At this time, only one active lawsuit remains pending in the U.S. District Court for Arizona, which concerns $8.3 million in remediation legal expenses. APS is unable to predict the outcome of any further litigation related to this claim or APS’s share of liability related to that claim; however, APS does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

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

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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 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. At the present time, we are unable to predict the outcome of this matter, and any further expenditures related to necessary remediation, if any, or further investigations cannot be reasonably estimated.

Four Corners National Pollutant Discharge Elimination System Permit

The latest NPDES permit for Four Corners was issued on September 30, 2019. Based upon a November 1, 2019 filing by several environmental groups, the Environmental Appeals Board 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 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.

Water Supply

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 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. A Tier 1 shortage reduces Arizona’s share of the Colorado River water by 18 percent or 512,000-acre feet; however, due to in-state conservation measures, Arizona has kept more Colorado River water in Lake Mead than is required by the shortage. Tier 1 reductions are largely felt by central Arizona’s agricultural users, mainly in Pinal County. Assured supplies of water are important for APS’s generating plants. At this time, a Tier 1 shortage does not materially impact water supplies used by APS’s fleet of generation resources. As drought conditions across the southwestern U.S. region continue to worsen, APS will monitor water availability necessary for continued Company operations and, as necessary, implement measures to mitigate risks associated with future Colorado River shortage declarations.

Conflicting claims to drought-impacted surface water in the southwestern United States have resulted in disputes and numerous court actions. The General Stream Adjudication allows the state to issue a final priority determination on claims to surface water rights. There are three General Stream Adjudications near APS generating stations that may impact surface water or groundwater supplies that are adjacent to surface water streams.

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San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require a number of years to resolve. APS is one of numerous parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. 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.

Gila River Adjudication. A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Arizona Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’s rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this adjudication. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Several of APS’s other power plants are also located within the geographic area subject to the summons, including a number of gas-fired power plants located within Maricopa and Pinal Counties. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Arizona Supreme Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter.

At this time, the lower court proceedings in the Gila River adjudication are in the process of determining the specific hydro-geologic testing protocols for determining which groundwater wells located outside of the subflow zone of the Gila River should be subject to the adjudication court’s jurisdiction. A hearing to determine this jurisdictional test question was held in March 2018 in front of a special master, and a draft decision based on the evidence heard during that hearing was issued on May 17, 2018. The decision of the special master, which was finalized on November 14, 2018, accepts the proposed hydro-geologic testing protocols supported by APS and other industrial users of groundwater. A further ruling affirming this decision by the trial court judge overseeing the adjudication was issued on July 8, 2022. 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, which rely on groundwater extraction to support their industrial operations. APS cannot predict the outcome of these proceedings.

Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. No trial or pretrial proceedings have been scheduled for adjudication of APS’s water right claims. 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

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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.

Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial condition, results of operations, or cash flows.

Human Capital

The Company’s success depends on a strong human capital strategy including attracting, developing, and retaining a high-performing workforce. We are committed to fostering a safe, inclusive, and engaging work environment that empowers all employees to reach their full potential. 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 table below presents the employee count as of December 31, 2025:

Principal Executive Office

AddressYear of

Formation
Approximate Number

of Employees at December 31, 2025

Pinnacle West400 North Fifth Street

Phoenix, AZ 85004198594

APS400 North Fifth Street

P.O. Box 53999

Phoenix, AZ 85072-399919206,516 (a)

El Dorado400 North Fifth Street

Phoenix, AZ 850041983—

PNW Power400 North Fifth Street

Phoenix, AZ 850042023—

Total 6,610

(a) Includes employees at jointly-owned generating facilities (approximately 2,400 employees) for which APS serves as the generating facility manager.

Approximately 1,120 APS employees are union employees represented by International Brotherhood of Electrical Workers (“IBEW”). On September 25, 2023, the IBEW membership ratified a new collective bargaining agreement (“CBA”) with APS. The new CBA became effective in October 2023 and has a duration of three years until April 1, 2026 and thereafter until either party gives notice of desire for change, amendment, or termination. On August 23, 2024, 27 IT Communications Field Specialists joined the existing bargaining unit represented by IBEW. 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.

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Culture and Engagement

The APS Promise anchors our commitment to our customers, community, and each other. The Promise explains our purpose, vision, and mission and the principles and behaviors that will empower us to achieve our strategic goals. 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.

We evaluate our success in building this culture in part through annual and quarterly employee engagement surveys, including our Employee Experience Index, which measures key aspects of engagement such as recognition, career development, and organizational pride. In 2025, we had 83% participation in these surveys, and our Employee Experience Index was 86%. These surveys enable us to compare our performance to industry benchmarks and identify areas for improvement.

Based on the survey results, we encourage business units and managers to take action. For example, past surveys have led to initiatives that we believe improved communication, removed job success obstacles, increased employee access to leadership, and enhanced meeting efficiency.

We actively seek feedback from new hires to further refine the employee onboarding experience. Our cross-functional Employee Engagement Council plays a key role in driving improvements, particularly in employee engagement and recognition.

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We believe that belonging matters. 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. Examples of the Company’s efforts in this space include the following:

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

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

Employee Safety

Our work and our decisions are anchored in safety – safety is the foundation of everything we do, and employee safety is our paramount responsibility as an employer. We develop practices and programs that ensure employees have safe and secure workplaces that allow them to perform at the highest levels. We utilize preventative programs like APS Moves to help keep our workforce healthy and prepare them to perform tasks safely. Our comprehensive safety programs and our focus on human and organizational performance and injury case management contribute significantly to our strong safety performance. As we continue to improve our safety performance, our ultimate goal remains serious injury reduction. We believe our employees are empowered to speak up when there are better or safer ways of doing business. Safety committees operate in organizations throughout the Company, providing opportunities for employees to positively impact their local safety cultures and performance. Additionally, the Company’s executive safety committee helps ensure strong safety governance and operational integration across the enterprise and employee-led learning teams help ensure that lessons learned from close calls and other safety incidents are shared for the benefit of employees across the enterprise.

Talent Strategy and Pipeline Development

Attracting and developing a highly skilled workforce is critical to our success. To this end, our talent strategy prioritizes the following:

•Commitment to Growth and Development: 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: Our pipeline strategy focuses on attracting and developing early- and mid-career talent for critical energy sector positions, including lineworkers, substation electricians, cybersecurity specialists, engineers, and nuclear power plant operators and technicians. We achieve this through an array of programs, including craft apprenticeships, engineering and rotational programs, and internships.

•Strategic Partnerships: We leverage partnerships with colleges, universities, vocational schools, and the Department of Defense SkillBridge program to access a wide pool of qualified candidates, including transitioning military personnel.

•Innovation in Talent Acquisition: 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

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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.

Succession Planning

Succession planning is critical to ensuring the long-term success of our Company. We have a robust process for identifying and developing high-potential leaders to fill key executive and other critical roles. This involves regularly reviewing and updating succession plans for key positions, identifying and assessing potential successors, and providing targeted development opportunities such as mentoring, coaching, and challenging rotational assignments. 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 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 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

PNW Power

PNW Power holds certain investments and assets that were previously held by BCE, a former subsidiary of Pinnacle West that was sold in 2024. PNW Power’s investments include TransCanyon, a 50/50 joint venture that was formed in 2014 with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. TransCanyon is pursuing independent electric transmission opportunities within the 11 U.S. states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the TransCanyon partners’ utility affiliates. These opportunities include the proposed 500-kV Cross-Tie

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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. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms. Clear Creek achieved commercial operation in May 2020; however, in the fourth quarter of 2022, PNW Power’s equity method investment was fully impaired. Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under long-term PPAs. PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.

El Dorado

El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. In particular, El Dorado has committed to and/or holds the following:

•$25 million investment in the Energy Impact Partners fund, of which approximately $20 million has been funded as of December 31, 2025. Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.

•$25 million investment in AZ-VC 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.

•$7.5 million investment in Westly Seed Fund, of which approximately $2 million has been funded as of December 31, 2025. Westly Seed Fund is focused on supporting entrepreneurs involved in the energy, mobility, building, and industrial sectors.

•Equity investment in SAI Advanced Power Solutions, 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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WHERE TO FIND MORE INFORMATION

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 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. The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, such as the Company, that file electronically with the SEC. The address of that website is www.sec.gov. Our board and committee charters, Code of Ethics for Financial Executives, Code of Ethics and Business Practices, and other corporate governance information is also available on the Pinnacle West website. Pinnacle West will post any amendments to the Code of Ethics for Financial Executives and Code of Ethics and Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange on its website. The information on Pinnacle West’s website is not incorporated by reference into this report.

You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Corporate Secretary, Mail Station 8602, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3011).