Item 1. BUSINESS

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.

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. Our reportable business segment activities are conducted primarily through our wholly-owned subsidiary, APS.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

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. During 2024, no single purchaser or user of energy accounted for more than 1.4% of our electric revenues.

The following map shows APS’s retail service territory, including the locations of its generating facilities and principal transmission lines.

Energy Sources and Resource Planning

To serve its customers, APS obtains power through its various generation stations and through purchased power agreements. 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 2024 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; and

• 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; managing demand with a modern interactive grid; promoting customer technology and energy efficiency; 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. 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

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 17% of Unit 2. In addition, APS leases approximately 12.1% 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. 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. See Note 17 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;

• 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 52% 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 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. The DOE has approved and paid approximately $156.7 million for these claims (APS’s share is approximately $45.6 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. See Note 3. 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 February 2025, the DOE approved approximately $17.6 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. 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. 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 10 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

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 3,573 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 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.

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. 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. 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.

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 has 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.

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. 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. 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/ Target Commercial Operation Date						Term (Years)						Net Capacity In Operation (MW AC)						Net Capacity Planned/Under Development (MW AC)
APS Owned
Solar:
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
Chino Valley						Chino Valley, AZ						2012												20
Hyder II						Hyder, AZ						2013												14
Foothills						Yuma, AZ						2013												38
Gila Bend						Gila Bend, AZ						2014												36
Luke AFB						Glendale, AZ						2015												11
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
Distributed Energy:
APS Owned (a)						AZ						Various												38
Total APS Owned																								416						168
PPAs
Solar:
Solana						Gila Bend, AZ						2013						30						250
RE Ajo						Ajo, AZ						2011						25						5
Sun E AZ 1						Prescott, AZ						2011						30						10
Saddle Mountain						Tonopah, AZ						2012						30						15
Badger						Tonopah, AZ						2013						30						15
Gillespie						Maricopa County, AZ						2013						30						15
Mesquite Solar 5						Tonopah, AZ						2023						20						60
Sunstreams 3						Arlington, AZ						2024						20						215
Yuma Solar Energy						Yuma County, AZ						2025						20												70
Harquahala Sun 2						Tonopah, AZ						2025						20												300
Sunstreams 4						Arlington, AZ						2025						20												300
Serrano Solar						Pima and Pinal County, AZ						2025						20												170
CO Bar Solar C						Coconino County, AZ						2027						20												206
Hashknife 1						Navajo County, AZ						2026						20												275
Catclaw						Buckeye, AZ						2026						20												225
Papago Solar						Maricopa County, AZ						2026						20												150
Hashknife 2						Navajo County, AZ						2027						20												200
Kitt						Eloy, AZ						2026						20												100
Pioneer						Yuma, AZ						2027						20												300
Maricopa Energy Center Phase 1						Maricopa County, AZ						2026						20												183
Maricopa Energy Center Phase 2						Maricopa County, AZ						2027						20												367
Snowflake Solar						Snowflake, AZ						2027						20												475
Wind:
Aragonne Mesa						Santa Rosa, NM						2022						20						200
High Lonesome						Mountainair, NM						2009						30						100
Perrin Ranch Wind						Williams, AZ						2012						25						99
Chevelon Butte						Winslow, AZ						2023						20						238
Chevelon Butte II						Winslow, AZ						2024						20						216
West Camp Wind Farm						Navajo County, AZ						2026						20												500

Geothermal:
Salton Sea						Imperial County, CA						2006						23						10
Biomass:
Snowflake						Snowflake, AZ						2008						25						14
Biogas:
NW Regional Landfill						Surprise, AZ						2012						20						3
Total PPAs																								1,465						3,821
Distributed Energy
Solar (b)
Third-party Owned						AZ						Various												1,694						63
Agreement 1						Bagdad, AZ						2011						25						15
Agreement 2						AZ						2011-2012						20-21						18
Total Distributed Energy																								1,727						63
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. 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.

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. See Note 15. 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 (MW)
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.

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 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.

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. 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.

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. 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”). 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. 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. 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 2024. 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

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 3 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 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.

Wholesale

FERC regulates rates for wholesale power sales and transmission services. See Note 3 for information regarding APS’s transmission rates. During 2024, approximately 4.2% 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 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.

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 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 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.

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 the EPA on June 19, 2019, and replaced by the Affordable Clean Energy (“ACE”) 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. 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. 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.

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. 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. 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. 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.

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. 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.

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 (“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. 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.

• 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. 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. 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. The Navajo Plant disposed of CCR only in a dry landfill storage area. 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 subject to alternative closure). 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. 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 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. 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.

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 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 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.

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. 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. 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. 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.

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. 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. 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”). 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 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. 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. 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 (“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. 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.

Water Supply

Based on a declaration from the U.S. Bureau of Reclamation, as of January 1, 2025, 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. 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.

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

						Principal Executive Office Address						Year of Formation						Approximate Number of Employees at December 31, 2024
Pinnacle West						400 North Fifth Street Phoenix, AZ 85004						1985						88
APS						400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999						1920						6,315			(a)
El Dorado						400 North Fifth Street Phoenix, AZ 85004						1983						—
PNW Power						400 North Fifth Street Phoenix, AZ 85004						2023						—
Total																		6,403

(a) Includes employees at jointly-owned generating facilities (approximately 2,300 employees) for which APS serves as the generating facility manager.

Approximately 1,180 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. Collective bargaining relating to these employees is ongoing.

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. 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 2024, we had 80% participation in these surveys, and our Employee Experience Index was 87%. 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.

We believe that belonging matters. We recognize that differences of identities, perspectives, and experiences is 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;

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

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

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, 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.

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

• 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: 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.

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. 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. 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. 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

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. The 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’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 venture partners’ utility affiliates. The U.S. 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.

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 power purchase agreements (“PPAs”). PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.

El Dorado

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:

• $25 million investment in the Energy Impact Partners fund, of which approximately $18.8 million has been funded as of December 31, 2024. 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. 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 $1.2 million has been funded as of December 31, 2024. 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.

The remainder of these investment commitments will be contributed by El Dorado as each investment fund selects and makes investments.

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 Securities and Exchange Commission (“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).