What changed in this filing

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Item 1. Business

2024-02-27 compared with 2023-02-27 · 221 added, 291 removed, 525 unchanged (49% of the section changed)

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

APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the State 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 subsidiaries are El Dorado, BCE and 4CA.

APS 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 subsidiaries are El Dorado, PNW Power, and 4CA.

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.

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APS currently provides electric service to approximately 1.4 million customers.

We own or lease 6,340 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity, including a variety of agreements for the purchase of renewable energy.

We own or lease 6,491 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity.

During 2023, no single purchaser or user of energy accounted for more than 2.1% of our electric revenues.

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APS’s sources of energy by type used to supply energy to Native Load customers during 2023 were as follows:

*Renewables include energy from wind, solar, geothermal, biomass, DG, and solar PPAs.

The share of APS’s energy supply being derived from clean resources is 51%, which includes energy from nuclear, renewables and DSM.

BCE also has acquired minority ownership positions in two wind farms that achieved commercial operation in 2020.

Both wind farms deliver power under long-term PPAs.

See “Business of Other Subsidiaries — Bright Canyon Energy” below for information regarding BCE’s investments.

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

The share of APS’s energy supply being derived from clean resources was approximately 51% in 2023, which includes energy from nuclear, renewables and DSM.

Clean Energy Focus Initiatives

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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 solar, wind, geothermal, biogas, and biomass.

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

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 goals consist of three parts:

APS’s Clean Energy Commitment consists of three parts:

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

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

• a commitment to end APS’s use of coal-fired generation by 2031.

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

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

• A commitment 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;

ceasing the use of coal-generated electricity;

exiting from coal-generated electricity;

managing demand with a modern interactive grid;

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

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

APS also voluntarily tracks APS’s GHG emissions arising from APS operations.

In addition to reporting to the EPA, we publicly report Scope 1, 2 and 3 GHG emissions.

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 ).

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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.

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.

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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 do not signal whether or when the NRC might authorize construction of the repository.

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.

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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 Court of Federal Claims.

This lawsuit sought to recover damages incurred due to the 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, as it was required to do pursuant to the terms of the Standard Contract and the NWPA.

On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by the DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011.

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.

An additional extension is currently pending.

APS has submitted eight claims pursuant to the terms of the August 18, 2014 settlement agreement for eight separate time periods during July 1, 2011 through June 30, 2021.

APS has submitted nine claims pursuant to the terms of the August 18, 2014 settlement agreement, for nine separate time periods during July 1, 2011 through October 31, 2022.

The DOE has approved and paid $138.2 million for these claims (APS’s share is $40.2 million).

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

On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $14.3 million (APS’s share is $4.2 million).

In February 2023, the DOE approved this claim.

On October 31, 2023, APS filed its tenth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $18.46 million (APS’s share is $5.4 million).

In February 2024, the DOE approved $18.39 million of this claim.

Waste Confidence and Continued Storage — On June 8, 2012, the D.C.

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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.

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.

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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 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.

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.

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APS has two oil-only power plants:

Fairview, located in the town of Douglas, Arizona and Yucca GT-4 in Yuma, Arizona.

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.

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

Additionally, 4CA, a wholly-owned subsidiary of Pinnacle West, owned 7% of Units 4 and 5 from July 2016 through July 2018 following its acquisition of El Paso’s interest in these units described below.

As part of APS’s Clean Energy Commitment, APS has committed to cease using coal-fired generation as part of its portfolio of electricity generating resources, including Four Corners, by 2031.

As part of APS’s Clean Energy Commitment, APS has committed 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 (the “2016 Coal Supply Agreement”).

El Paso, a 7% owner of Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement.

Under the 2016 Coal Supply Agreement, APS agreed to assume the 7% shortfall obligation.

On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners.

4CA purchased the El Paso interest on July 6, 2016.

The purchase price was immaterial in amount, and 4CA assumed El Paso’s reclamation and decommissioning obligations associated with the 7% interest.

On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA’s 7% interest in Four Corners.

NTEC assumed 4CA’s reclamation and decommissioning obligations associated with the 7% interest.

The sale transaction closed on July 3, 2018.

NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million and paid the purchase price over four years pursuant to a secured interest-bearing promissory note, which was paid in full as of June 30, 2022.

In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7% share of capital expenditures and operating and maintenance expenses.

Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

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.

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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 beginning in fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership.

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

In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners as early as fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership.

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

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

APS anticipates that it will elect not to begin seasonal operation in November 2023, unless market conditions change.

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.

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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 by 2025.

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

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

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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, which it owns and operates.

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.

Two of our large customers purchase renewable energy credits from APS that are equivalent to the amount of renewable energy that Red Rock is projected to generate.

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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

APS has also developed solar photovoltaic distributed renewable energy 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 distributed renewable energy systems located within a certain test area in Flagstaff, Arizona.

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.

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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.

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.

In 2018, APS issued a request for proposal (“RFP”) for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites.

Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site.

These battery storage facilities are currently expected to be in service during the first quarter of 2023.

On August 2, 2021, APS executed a contract for an additional 60 MW of utility-owned energy storage to be located on APS’s AZ Sun sites.

This contract, with a 2023 in-service date, will complete the addition of storage on current APS-owned utility-scale solar facilities.

Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW.

These PPAs were subject to ACC approval in order to allow for cost recovery through the PSA.

APS received the requested ACC approval on January 12, 2021, and service under the agreements is expected to begin in 2023.

In December 2020, APS issued two RFPs (collectively, the “December 2020 RFPs”).

As a result of the December 2020 RFPs, APS executed four 20-year PPAs for resources that include energy storage:

(a) two PPAs for standalone energy storage resources totaling 300 MW;

and (b) two PPAs for solar plus storage resources totaling 275 MW.

The PPAs are also subject to ACC approval to enable cost recovery through the PSA.

APS received the requested ACC approval for three out of four of the projects on December 16, 2021 and on April 13, 2022 for the remaining project.

Service under the agreements is expected to begin in 2023 and 2024.

In May 2022, APS issued an RFP to address resource needs for 2025 and beyond (the “2022 RFP”).

As a result of the 2022 RFP, as of January 2023, APS has executed a 20-year PPA for solar plus storage resources totaling 300 MW.

The PPA is subject to ACC approval to enable cost recovery through the PSA, which was requested in December 2022 and approved in February 2023.

Service under this agreement is expected to begin in 2025.

APS currently plans to install more than 1,200 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above.

The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2022.

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

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

APS Owned Energy Storage

PPAs Energy Storage —

Residential Energy Storage 19(a) 7

Total Energy Storage Portfolio

(a) This includes 18.5 MW of APS customer-owned batteries and 0.2 MW of APS-owned residential batteries.

Renewable Energy Portfolio

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Renewable resources in operation include 415 MW of facilities owned by APS, 1,034 MW of long-term purchased power agreements, and an estimated 1,623 MW of customer-sited, third-party owned distributed energy resources.

As previously discussed, in May 2022, APS issued an RFP to address resource needs for 2025 and beyond.

The 2022 RFP solicits competitive proposals for approximately 1,000 MW to 1,500 MW of resources, including up to 600 MW to 800 MW of renewable resources to meet the needs of 2025 and 2026 while also considering resources that can be online as late as 2027.

The 2022 RFP stopped accepting bids on July 15, 2022, and APS sent notifications to shortlisted bidders on September 23, 2022.

As a result of the 2022 RFP, and as of December 31, 2022, APS has signed a PPA for 300 MW of solar plus energy storage resources and a PPA for 216 MW of wind resources.

Once APS secures those important resources and closes out the 2022 RFP, APS intends to issue APS’s next RFP to address future resource needs.

On June 30, 2023, APS issued an All-Source Request for Proposal (“RFP”) seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources with a focus on in-service dates between 2026 and 2028 (the “2023 RFP”).

Bids from the 2023 RFP were received on September 6, 2023, and APS has started negotiations on multiple projects, including a 400 MW wind facility PPA that was signed in December 2023.

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” above for more information regarding APS-owned energy storage facilities.

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 December 31, 2023.

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Total APS Owned 415 —

Purchased Power Agreements

Solana Gila Bend, AZ 2013 30 250

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Gillespie Maricopa County, AZ 2013 30 15

CO Bar Solar A Coconino County, AZ 2023 18 80

CO Bar Solar B Coconino County, AZ 2023 18 80

CO Bar Solar C Coconino County, AZ 2025 20 206

Mesquite Solar 5 Tonopah, AZ 2023 20 60

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Sunstreams 4 Arlington, AZ 2025 20 300

Harquahala Sun Tonopah, AZ 2025 20 300

Serrano Solar Pima and Pinal County, AZ 2025 20 170

Yuma Solar Energy Yuma County, AZ 2024 20 70

Aragonne Mesa Santa Rosa, NM 2022 20 200

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Chevelon Butte II Winslow, AZ 2024 20 216

West Camp Wind Farm Navajo County, AZ 2025 20 400

Salton Sea Imperial County, CA 2006 23 10

1 unchanged sentence

NW Regional Landfill Surprise, AZ 2012 20 3

Total Purchased Power Agreements 736 1,189

Total PPAs 1,034 1,877

Distributed Energy

7 unchanged sentences

DG is produced in DC and is converted to AC 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.

As noted above, on June 30, 2023, APS issued the 2023 RFP seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources, including energy storage, with a focus on in-service dates between 2026 and 2028.

APS currently plans to install more than 2,700 MW of utility scale energy storage by 2026, including through energy storage projects under PPAs and AZ Sun retrofits as well as through resources solicited through current and future RFPs.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2023.

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

Net Capacity in

Operation (MW) Net Capacity Planned /

Under Development (MW)

APS Owned Energy Storage 182 (a) 19 (b)

PPAs Energy Storage 60 2,182

Customer-Sited Energy Storage 30 20

Total Energy Storage Portfolio 272 2,221

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

(b) Includes 19 MW of capacity that entered commercial operation in January 2024.

Purchased Power Contracts

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Demand Response Agreement Summer seasons through 2025 75

Tolling Agreement May 1 through October 31, 2021-2027 463

Tolling Agreement Summer seasons from Summer 2020 through Summer 2025 565

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 570

Renewable Energy (b) Various 1,063

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

Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio.”

Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard.”

Current and Future Resources

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

APS’s 2022 peak one-hour demand on its electric system was recorded on July 11, 2022, at 7,587 MW, compared to the 2021 peak of 7,580 MW recorded on June 18, 2021.

APS’s 2023 peak one-hour demand on its electric system was recorded on July 15, 2023, at 8,162 MW, compared to the 2022 peak of 7,587 MW recorded on July 11, 2022.

APS’s reserve margin at the time of the 2023 peak demand, calculated using system load serving capacity, was 18%.

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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 requirements and whether it should be acknowledged.

Based on an ACC decision, APS was originally required to file its IRP by April 1, 2020.

On February 20, 2020, the ACC extended the deadline for all utilities to file their IRPs from April 1, 2020, to June 26, 2020.

On June 26, 2020, APS filed its final IRP.

On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021.

In February 2022, the ACC acknowledged APS’s IRP.

The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030.

Due to current projected future resource needs and load forecasts, APS continues to need to develop or acquire additional capacity.

APS intends to file its next IRP later in 2023.

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

APS was originally required to file its IRP by August 1, 2023.

However, on May 1, 2023, APS, Tucson Electric Company, and UNS Electric, Inc., filed a joint request to extend the IRP filing due date to November 1, 2023, which the ACC granted on June 21, 2023.

APS filed its 2023 IRP on November 1, 2023.

On January 31, 2024, stakeholders filed comments regarding the IRP.

APS cannot predict the outcome of this matter.

On October 4, 2023, the ACC updated the IRP processing timeline with a due date of August 30, 2024 for the ACC Staff Assessment and Proposed Order and an open meeting decision due date yet to be determined.

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.

Energy Imbalance Market & Wholesale Market

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

The EIM 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 EIM 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 is in discussions with the EIM operator, CAISO, and other EIM participants about the feasibility of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.

APS also is in discussions with Southwest Power Pool, a market operator developing a day-ahead and real-time market for the Western Interconnection.

In addition, APS is participating in the Western Resource Adequacy Program administered by the Western Power Pool.

Western Energy Imbalance Market & 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 is participating in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool.

APS also participated in the design and drafting of the tariff for the CAISO’s Extended Day-Ahead Market, which was approved by FERC in December 2023.

In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool.

These efforts are driven by three objectives of reducing customer cost, improving reliability, and incorporating more clean energy on APS’s system.

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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 baseline carbon emissions level:

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;

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Instead, the ACC opened a new docket to consider All-Source RFP requirements and the IRP process.

During the August 2022 ACC Open Meeting, Commissioners voted to postpone a decision on the All-Source RFP and IRP rulemaking package until 2023.

During the August 2022 ACC Open Meeting, the ACC voted to postpone a decision on the All-Source RFP 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.

APS cannot predict the outcome of this matter.

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The renewable energy requirement is 13% of retail electric sales in 2023 and increases annually until it reaches 15% in 2025.

A component of the RES is focused on stimulating development of distributed renewable energy systems.

A component of the RES is focused on stimulating development of DG systems.

Accordingly, under the RES, an increasing percentage of that requirement must be supplied from distributed energy resources.

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On July 1, 2021, APS filed its 2022 RES Implementation Plan, which was subsequently amended on December 9, 2021.

On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an

amendment requiring a stakeholder working group to convene and develop a community solar program for the Commission’s consideration at a future date.

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 September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group.

APS is proposing a small, pilot scale program size of up to 140 MW that would be selected through a competitive RFP.

APS proposed a small, pilot scale program size of up to 140 MW that would be selected through a competitive RFP.

The ACC has not yet ruled on the proposal.

However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components.

The community solar program was deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar.

On March 23, 2023, the ACC approved a policy statement that included information on how statewide community solar and storage programs should be structured, their location, and inclusion in RFPs.

The remainder of the community solar program policy components were deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar.

APS cannot predict the outcomes of these future activities.

On July 1, 2022, APS filed its 2023 RES Implementation Plan, and 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.

The following table summarizes the RES requirement standard and its timing:

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

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

some or all of their own energy requirements.

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

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

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Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories.

APS opposes Green Mountain Energy’s application and intends to intervene to contest it.

On November 3, 2021, the ACC submitted questions to the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates convenience and necessity.

On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided insights on the applicable law.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier.

APS opposes Green Mountain Energy’s application.

On November 3, 2021, the ACC submitted questions to the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates convenience and necessity.

On November 26, 2021,

the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided insights on the applicable law.

As the ACC’s questions pertained to the retail competition law subsequently repealed in April 2022, the Attorney General has not responded to the ACC’s request and the questions are now moot.

No action has been taken by the ACC regarding this application since that time.

However, on May 17, 2023, the Retail Energy Supply Association filed a motion with the ACC requesting it to re-open the generic docket to re-examine the ACC’s electric competition rules.

No action has been taken by the ACC regarding this motion.

APS cannot predict the outcome of these matters.

On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200 to 300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier.

The letter also states that similar programs should be designed for other Arizona regulated electric utilities.

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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.

This Ten-Year 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 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.

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While Arizona has no pending legislation regulating GHGs, the California legislature enacted AB 32 and SB 1368 in 2006 to address GHG emissions.

In October 2011, the California Air Resources Board 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.

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.

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.

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

On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations.

EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations.

On January 19, 2021, the U.S.

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 vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling.

That decision, which endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP, was subsequently reversed by the U.S.

Supreme Court on June 30, 2022.

While the current administration has expressed its intent to develop new carbon emission regulations governing existing power plants sometime in 2023, such action will be constrained by the U.S.

Supreme Court’s decision that the CPP violated the Clean Air Act.

Nonetheless, we cannot at this time predict the outcome of pending EPA rulemaking proceedings related to carbon emissions from existing power plants.

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 latest set of proposed rules, released on May 23, 2023, EPA contemplates 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, the most recent proposal is limited to measures that can be installed at individual power plants to limit planet-warming emissions.

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”) or varying levels of hydrogen gas (“H2”) co-firing.

As for existing natural gas-fired combustion turbines, EPA is imposing similar control requirements at large, high utilization generating units, but is otherwise not proceeding at this time with further regulation.

Under EPA’s proposal, this means that both new and existing peaking gas-fired combustion turbines (i.e., those with a 20% or less annual capacity factor) are effectively unregulated under the proposed regulations.

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

This means that facilities retiring between 2030 and before 2040 must meet increasingly stringent emission limits up to natural-gas co-firing starting in 2030.

However, for those facilities with no planned retirement date prior to 2040, EPA is requiring those plants to be retrofitted with CCS controls by 2030.

At this time, APS cannot predict the outcome of this rulemaking or when EPA will take final action.

In addition, APS is continuing to evaluate this proposal and its potential impact on APS’s operations.

Depending on the eventual outcome, the costs associated with APS’s operation of its current and future thermal power plants could materially increase, which could affect our financial condition, results of operations, or cash flows.

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 our coal 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 fossil-fuel powered plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.

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

Regional Haze Rules .

In 1999, EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas.

The rules require states (or, for sources located on tribal land, EPA) to determine what pollution control technologies constitute the BART for certain older major stationary sources, including fossil-fuel fired power plants.

EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis.

Final regulations imposing BART requirements have now been imposed on each APS coal-fired power plant.

Four Corners was required to install new pollution controls to comply with BART, while similar pollution control installation requirements were not necessary for Cholla.

In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.

In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by

PacifiCorp retired Cholla Unit 4 at the end of 2020.

See “Cholla” in Note 3 for information regarding future plans for Cholla and details related to the resulting regulatory asset.

Four Corners .

Based on EPA’s final standards, APS’s 63% share of the cost of required BART controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred.

See Note 3 for information regarding the related rate recovery.

In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in Four Corners Units 4 and 5.

4CA purchased the El Paso interest on July 6, 2016.

NTEC purchased the interest from 4CA on July 3, 2018.

The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Coal Combustion Waste.

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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.

While certain changes have been prompted by utility industry petitions,

others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA.

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

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

Although ADEQ has taken steps to develop a CCR permitting program, including supporting the passage of new state legislation providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect.

On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

Although ADEQ has taken steps to develop a CCR permitting program, and new state legislation has been adopted providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect.

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.

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

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

• 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.

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

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

On January 11, 2022, EPA began issuing proposed decisions pursuant to this provision of the federal CCR regulations and APS anticipates receiving a proposed decision with respect to the Cholla facility in 2024.

• On May 18, 2023, EPA published a proposal that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015.

EPA proposes to defi ne a new class of CCR management units (“CCRMUs”) that 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.

EPA expects to finalize this proposal by spring of 2024.

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 APS’s financial position, results of operations, or cash flows.

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.

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

APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million.

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

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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.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment

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

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In addition, APS will also solicit input from the public and host public hearings as part of this process.

Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years.

The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time.

APS’s estimates for its share of corrective action and monitoring costs at Four Corners and Cholla are captured within the Asset Retirement Obligations in Note 11.

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 process, we cannot predict any ultimate impacts to the Company;

however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations, or cash flows.

Given uncertainties that may exist until we have fully completed the corrective action assessment and final remedy selection process, APS cannot predict any ultimate impacts to the APS;

however, at this time, APS does not believe that any potential changes to the cost estimate for Four Corners or Cholla would have a material impact on our financial condition, results of operations, or cash flows.

Effluent Limitation Guidelines .

On September 30, 2015, EPA finalized revised effluent limitation guidelines (“ELG”) establishing technology-based wastewater discharge limitations for fossil-fired EGUs.

EPA’s final regulation targets metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and coal ash disposal leachate.

Based upon an earlier set of preferred alternatives, the final effluent limitations generally require chemical precipitation and biological treatment for flue gas desulfurization scrubber wastewater, “zero discharge” from fly ash and bottom ash handling, and impoundment for coal ash disposal leachate.

On August 11, 2017, EPA announced that it would be initiating rulemaking proceedings to potentially revise the September 2015 ELGs.

On September 18, 2017, EPA finalized a regulation postponing the earliest date on which compliance with the ELGs for these waste-streams would be required from November 1, 2018, until November 1, 2020.

At this time, APS’s National Pollutant Discharge Elimination System (“NPDES”) discharge permit for Four Corners contains a December 31, 2023,

compliance deadline for achieving “zero discharge” of bottom ash transport waters.

Nonetheless, on October 13, 2020, EPA published a final rule relaxing these “zero discharge” limitations for bottom ash handling water and allowing for approximately 10% of such wastewater to be discharged (on a volumetric, 30-day rolling average basis) under limited power plant operating scenarios.

At this time, APS is pursuing a modification to the Four Corners NPDES discharge permit in order to implement the most recent ELG rulemaking.

We cannot at this time predict the outcome of this permit modification proceeding, including any public commenting or permit appeal procedures.

The Cholla facility does not require NPDES permitting.

Based on the most recently finalized effluent limitation guidelines (“ELG”), published by EPA on October 13, 2020, APS completed an NPDES permit modification for Four Corners on December 1, 2 023.

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

Nonetheless, on March 29, 2023, EPA proposed again for the bottom ash transport water ELG to shift back to a “zero discharge” standard.

EPA anticipates finalizing these standards by spring or summer of 2024.

In the event these standards are finalized as proposed, a further modification to the Four Corners NPDES permit would be required.

We cannot at this time predict the outcome of this rulemaking nor whether future regulatory action by EPA would have impact s on our financial condition, results of operations, or cash flows.

Ozone National Ambient Air Quality Standards.

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We anticipate that revisions to the SIPs and FIPs implementing required controls to achieve the new 70 ppb standard will be in place between 2023 and 2024.

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 the Company.

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.

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

Power plant emission limitations are a key aspect of these regulations, which involve emission allowance trading for nitrogen oxide emissions.

While Arizona was not among the 23 states subject to EPA’s March 2023 final action, EPA announced at this time that it was considering the inclusion of Arizona within a future regulatory action under the “good neighbor” provisions of the Clean Air Act.

APS cannot at this time predict the outcome of future “good neighbor” rulemakings by EPA or the extent to which such regulations, if they are finalized, may impact our financial condition, results of operations, or cash flows.

Superfund-Related Matters.

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APS anticipates incurring additional expenditures in the future, but because the ultimate remediation requirements are not yet finalized by EPA, at the present time, expenditures related to this matter cannot be reasonably estimated.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.

The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.

The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.

state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.

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, which is on appeal to the U.S.

Court of Appeals for the Ninth Circuit based on a U.S.

District Court order dismissing cost recovery claims of approximately $20.7 million by a service provider for RID.

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 our financial condition, results of operations, or cash flows.

In addition, as part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.

APS responded to ADEQ on May 4, 2015.

On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation.

That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation but excluded APS and certain other parties as named defendants.

Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery.

APS’s share of this settlement was immaterial.

In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice.

An order to this effect was entered on April 17, 2018.

With this disposition of the case, the vendors may file their lawsuit again in the future.

On August 16, 2019, Maricopa County, one of the three direct defendants in the ancillary service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants.

While this lawsuit remains pending, on September 30, 2022, the U.S.

District Court for the District of Arizona granted partial summary judgment to the direct defendants for $20.6 million of the $21 million in CERCLA response costs claimed by the service provider.

We are unable to predict the outcome of any further litigation related to the remaining response costs at issue in this litigation;

however, we do not expect the outcome to have a material impact on our financial position, results of operations, or cash flows.

Since that time, ADEQ has taken no action based on the information provided by APS.

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.

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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.

At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.

Manufactured Gas Plant Sites.

Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants.

APS is taking action to voluntarily remediate these sites.

APS does not expect these matters to have a material adverse effect on its financial position, results of operations, or cash flows.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board (“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.

The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised ELGs for steam-electric EGUs, 2014 existing-source

regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.

To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018, to withdraw the NPDES permit reissued in June 2018.

Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis.

The EAB thereafter dismissed the environmental group appeal on February 12, 2019.

EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019.

Based upon a November 1, 2019, filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit.

Oral argument on this appeal was held on September 3, 2020, and the EAB denied the environmental group petition on September 30, 2020.

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 this 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 is not expected to have a material impact on APS’s financial position, results of operations, or cash flows.

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 our financial condition, results of operations, or cash flows.

Based on a declaration from the U.S.

Bureau of Reclamation, as of January 1, 2023, Arizona’s supply of Colorado River water will be subject to a Tier 2a shortage.

Bureau of Reclamation, as of January 1, 2024, Arizona’s supply of Colorado River water will be subject to a Tier 1 shortage.

This shortage will result in a reduction to Arizona’s share of the Colorado River water by 28 percent or 792,000-acre feet.

This reduction, similar to the 2022 tier 1 shortage, will largely be felt by central Arizona’s agricultural users, mainly in Pinal County.

In light of pre-existing mitigation measures at the state level, the Tier 2a shortage is not expected at this time to materially impact water supplies for customers in APS’s service territory, nor materially impact water supplies used by APS’s fleet of generation resources.

This reduction will largely be felt by central Arizona’s agricultural users, mainly in Pinal County.

In light of pre-existing mitigation measures at the state level, the Tier 1 shortage is not expected at this time to materially impact water supplies for customers in APS’s service territory, nor materially impact water supplies used by APS’s fleet of generation resources.

As drought conditions across the southwestern U.S.

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

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

and is a party to a shortage sharing agreement, which provides for the apportionment of water supplies to Four Corners in the event of a water shortage in the San Juan River Basin.

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 and is a party to a shortage sharing agreement, which provides for the apportionment of water supplies to Four Corners in the event of a water shortage in the San Juan River Basin.

Gila River Adjudication.

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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 position, results of operations, or cash flows.

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

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We develop safety practices and programs that ensure employees have safe and secure workplaces that allow them to perform at the highest levels.

We use preventative programs such as the APS Moves program to help our workforce stay 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.

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Safety committees operate in organizations throughout the Company, providing opportunities for employees to positively impact their local safety cultures and performance.

Diversity, Equity, and Inclusion

Inclusion and Belonging

We believe that belonging matters.

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Each year since 2020, we have conducted company-wide executive listening sessions to provide employees with opportunities to be heard on their experiences at the Company.

In 2019, we signed the UNITY Pledge in support of full inclusion and equality in employment, housing, and public

accommodations for all Arizonans, including gay and transgender people.

The UNITY Pledge reinforces our commitment to fostering an environment that recognizes our employees’ unique needs and celebrates the value of diverse perspectives.

The Company sponsors ten employee network groups that are intended to create a sense of inclusion and belonging for employees.

In 2019, we signed the UNITY Pledge in support of full inclusion and equality in employment, housing, and public accommodations for all Arizonans, including gay and transgender people.

The UNITY Pledge reinforces our commitment to fostering an environment that recognizes our employees’ unique needs and celebrates

the value of diverse perspectives.

The Company sponsors eleven employee network groups that are intended to create a sense of inclusion and belonging for employees.

We continue to focus on hiring diverse employees as well as hiring employees from our veteran community.

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Succession Planning

Through a strong focus on succession planning, we ensure that our Company is prepared to fill executive and other key leadership roles with capable, experienced employees.

We continually revisit and revise succession plans to make certain that qualified individuals are in place to move into critical positions.

We have strategically selected successors for our management team to lead our Company into the future with strong and sustainable performance.

In addition, we assure that each business unit of the Company has talent management strategies and development plans to meet its future leadership needs.

Effective succession planning helps us identify employees with leadership potential and also allows us to evaluate any gaps in education, skills and experience that need to be addressed to prepare those employees to move into leadership roles.

At management review meetings, officers and directors review how business units are addressing succession planning, leadership opportunities, and retirement projections.

Succession planning ensures that our Company is prepared to fill executive and other key leadership roles with capable, experienced employees who can lead us into the future with strong and sustainable performance.

We continually revisit and revise succession plans to make certain qualified individuals are in place to move into critical positions.

In addition, we provide each business unit of the Company with talent management strategies and development plans to meet its future leadership needs.

Effective succession planning helps us identify employees with leadership potential, evaluate any gaps in education, skills and experience, and support employees in preparation for their next leadership roles.

Officers and directors review succession plans, leadership opportunities, and retirement projections to ensure business continuity.

Talent Strategy and Development

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In 2023, we graduated 152 individuals from our three academies (Leadership Academy, Impact and Influence Academy, and Strategic Leadership Academy).

Additionally, our Learning and Development organization was recognized as a top training organization, earnings an APEX Award from Training Magazine.

Talent pipelines help sustain our skilled workforce needs.

Pipeline strategies include our apprentice and rotational programs.

Additionally, our recruiters target specific colleges and programs of study that we have identified as talent pipelines.

In 2022, we hosted 54 summer interns with a diversity rate of 63%.

Our pipeline strategy is driven by a robust portfolio of programs aimed at attracting early and mid-career talent.

With over a dozen programs in effect, our talent pipelines include craft apprenticeships and engineering, rotational, and internship programs.

We partner closely with specific colleges and universities, vocational schools, and organizations serving local communities to attract a large pool of qualified, diverse talent.

Additionally, 2023 marked the launch of the Department of Defense SkillBridge program, which provides APS early access to transitioning military talent to fill open roles.

During 2023, we hosted 57 summer interns with an overall diversity rate of 67% and also comprised of 35% women.

In addition to our summer program, 14 participated as Maintenance Interns, Radiation Protection Interns, and Pre-Apprentice Interns (programs specifically offered at Palo Verde).

Total Rewards Strategy

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Through an outreach initiative, we obtain feedback from new hires regarding their employee experience.

In 2019, we integrated our employee experience surveys with onboarding surveys and exit interviews.

Bringing together these elements allows us to get a more complete picture of the experience of our employees, from the time they join the Company until they decide to leave.

Company Culture

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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.

BUSINESS OF OTHER SUBSIDIARIES

Bright Canyon Energy

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.

BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry.

As of December 31, 2022, BCE had total assets of approximately $115.3 million.

In 2014, BCE formed a 50/50 joint venture with BHE U.S.

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.

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 Pinnacle West Power, LLC (“PNW Power”), a newly-formed, 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.

The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 U.S.

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.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska Energy, Inc.

and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek wind farm in Missouri (“Clear Creek”) and the 250 MW Nobles 2 wind farm in Minnesota (“Nobles 2”).

Clear Creek achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020.

PNW Power’s investments also include minority ownership positions in two wind farms operated by Tenaska Energy, Inc.

and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms.

Clear Creek achieved commercial operation in May 2020;

however, in the fourth quarter of 2022 PNW Power’s equity method investment was fully impaired.

Nobles 2 achieved commercial operation in December 2020.

Both wind farms deliver power under long-term PPAs.

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

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022.

Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order.

On October 7, 2022, the request for rehearing was denied by FERC.

FERC has not ruled on the motion for stay.

Clear Creek has filed a Petition for Review with the U.S.

Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.

Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner.

The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.

Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors.

These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion, or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC.

As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired.

Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment ’ s estimated fair value of zero as of December 31, 2022.

Pinnacle West ’ s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $12.8 million relating to this impairment.

BCE has started construction on a microgrid facility in Los Alamitos, California (“Los Alamitos”) featuring 31 MW of solar, 20 MW of battery storage, and 3 MW of backup generators.

Supported by a long-term PPA with San Diego Gas and Electric Company, Los Alamitos will supply 20 MW of solar and battery storage capacity to the Southern California grid and provide resilient backup power in the event of a grid emergency to the Army and California National Guard at Joint Forces Training Base Los Alamitos.

The Los Alamitos project is scheduled to achieve commercial operation in third-quarter 2023.

See Note 6 regarding a credit agreement entered into by BCE to finance capital expenditures and related costs for this microgrid project.

BCE and Ameresco, Inc.

jointly own a special purpose entity that is sponsoring the Kūpono Solar project.

This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year PPA with Hawaiian Electric Company, Inc.

The Kūpono Solar project is expected to be completed in 2024.

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

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

El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures.

El Dorado is actively seeking to prudently realize the value of these investments.

In particular, El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.

The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.

As of December 31, 2022, El Dorado has contributed approximately $12.5 million to the Energy Impact Partners fund.

Additionally, El Dorado committed to a $25 million investment in AZ-VC (formerly invisionAZ Fund), which 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 the State of Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in the State of Arizona.

As of December 31, 2022, El Dorado has contributed approximately $2.6 million to the AZ-VC.

The remainder of the investments will be contributed by El Dorado as investments are selected by the AZ-VC.

In particular, El Dorado has committed to the following:

• $25 million investment in the Energy Impact Partners fund, of which $16.7 million has been funded as of December 31, 2023.

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 $6.3 million has been funded as of December 31, 2023.

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.

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

Pinnacle West, APS and El Dorado are all incorporated in the State of Arizona.

BCE and 4CA are incorporated in Delaware.

PNW Power is incorporated in Delaware.

Additional information for each of these companies is provided below:

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BCE 400 East Van Buren Street

Phoenix, AZ 85004 2014 7

Phoenix, AZ 85004 2014 7 (a)

El Dorado 400 East Van Buren Street

Phoenix, AZ 85004 1983 —

4CA 400 East Van Buren Street

Phoenix, AZ 85004 2016 —

(a) See Note 20 for information related to the sale of Bright Canyon Energy.

The APS number includes employees at jointly-owned generating facilities (approximately 2,200 employees) for which APS serves as the generating facility manager.

Approximately 1,150 APS employees are union employees, represented by the International Brotherhood of Electrical Workers (“IBEW”).

In March 2020, the Company concluded negotiations with the IBEW and approved a three-year extension of the contract set to expire on April 1, 2020.

Under the extension, union members received wage increases for 2020, 2021 and 2022;

there were no other changes.

The current contract expires on April 1, 2023, and APS and the IBEW are currently engaged in negotiations to renew the contract.

On September 25, 2023, the IBEW membership ratified a new collective bargaining agreement (“CBA”) with APS.

The new CBA became effective in October 2023.

This new contract has a duration of three years and becomes amendable on April 1, 2026.

WHERE TO FIND MORE INFORMATION

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What changed 10-K

Item 1. Business