What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2022-02-25 compared with 2021-02-24 · 247 added, 209 removed, 522 unchanged (47% of the section changed)

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APS’s sources of energy by type used to supply energy to Native Load customers during 2021 were as follows:

*Renewables include energy from wind, solar, geothermal, biomass, distributed generation and solar power purchase agreements.

The share of APS’s energy supply being derived from clean resources is 50%.

*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 50%, 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 power purchase agreements.

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

Both wind farms deliver power under long-term PPAs.

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

Clean Energy Focus Initiatives

In response to climate change, the entire electric utility industry, as well as the global economy, is in the midst of a profound transition to clean energy and a new low-carbon economy.

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

(See “Energy Sources and Resource Planning — Current and Future Resources” below for details of these plans and initiatives.) APS currently has a diverse portfolio of renewable resources, including 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.

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.

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:

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and optimizing regional resources.

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

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

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

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

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

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

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

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

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APS also voluntarily tracks the full scope of APS’s GHG emissions arising from all APS operations.

In addition to GHG emissions from generation and transmission and distribution operations, this data includes all other GHG emissions arising from ancillary APS operations, such as vehicle use, employee travel, portable generators and facility energy usage.

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

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

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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.

In addition, APS leases approximately 12.1% of Unit 2, resulting in a

29.1% combined ownership and leasehold interest in that unit.

APS has a total entitlement from Palo Verde of 1,146 MW.

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

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

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

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

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

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

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

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The Palo Verde participants have contracted for 100% of Palo Verde’s requirements for uranium concentrates through 2028 and 86% through 2029;

100% of Palo Verde’s requirements for conversion services through 2030;

100% of Palo Verde’s requirements for conversion services through 2026 and 30% through 2030;

100% of Palo Verde’s requirements for enrichment services through 2026 and 76% for 2027;

and 100% of Palo Verde’s requirements for fuel fabrication through 2027.

and 100% of Palo Verde’s requirements for fuel fabrication through 2027 for Unit 2 and Unit 1 and 2028 for Unit 3.

Spent Nuclear Fuel and Waste Disposal — The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to accept, transport, and dispose of spent nuclear fuel and high-level waste generated by the nation’s nuclear power plants by 1998.

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

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

Several legal

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

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

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

APS is directly involved in legal proceedings related to the

DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high level waste.

APS is directly involved in legal proceedings related to the DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high-level waste.

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

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In addition, the settlement agreement provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2022.

APS has submitted and received payment for six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019.

The DOE has paid $99.7 million for these claims (APS’s share is $29 million).

APS has submitted seven claims pursuant to the terms of the August 18, 2014, settlement agreement, for seven separate time periods during July 1, 2011, through June 30, 2020.

The DOE has approved and paid $111.8 million for these claims (APS’s share is $32.5 million).

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

APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on November 2, 2020 in the amount of $12.2 million (APS’s share is $3.6 million).

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

On November 1, 2021, APS filed its eighth claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $12.2 million (APS’s share is $3.6 million).

In February 2022, the DOE approved 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.

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.

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

Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in

November 2047.

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.

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APS has a total entitlement from these plants of 3,573 MW.

A portion of the gas for these plants is financially hedged up to five years in advance of purchasing and that position is converted to a physical gas purchase one month prior to delivery.

A portion of the gas for these plants is financially hedged up to three years in advance of purchasing and that position is converted to a physical gas purchase one month prior to delivery.

APS has long-term gas transportation agreements with three different companies, some of which are effective through 2027.

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In total, this increased the capacity of the site by 290 MW to 620 MW.

(See Note 4 for rate recovery as part of the ACC final written Opinion and Order issued reflecting its decision in APS’s general retail rate case (the “2017 Rate Case Decision”) and the 2019 Retail Rate Case Filing).

See Note 4 for rate recovery as part of the ACC final written Opinion and Order issued reflecting its decision in APS’s general retail rate case (the

“2017 Rate Case Decision”) and the 2019 Retail Rate Case Filing.

The Ocotillo modernization project was completed in 2019.

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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.

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.

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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.

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

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest.

Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest.

These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales.

The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019.

Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations.

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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On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules.

On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the Unit.

Unit 2 on October 1, 2015.

On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without

expressing any view on the future recoverability of APS’s remaining investment in the Unit.

APS closed Unit 2 on October 1, 2015.

Following the closure of Unit 2, APS has a total entitlement from Cholla of 381 MW.

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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 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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In addition, APS has a coal transportation contract that runs through 2024.

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

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

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

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

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

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

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

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

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

APS will seek continued recovery in rates for the book value of its remaining investment in the plant (see Note 4 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material.

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

See Note 4 for details related to the resulting regulatory asset plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material.

See Note 11 for information regarding APS’s coal mine reclamation obligations related to these coal-fired plants.

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

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

Additionally, APS owns

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

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

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

APS Solar Communities (formerly AZ Sun II) is a three-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned distributed generation systems on low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities.

APS Solar Communities (formerly AZ Sun II) is a three-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems on low to moderate income residential homes, non-profit entities, Title I schools, and rural government facilities.

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

Currently, APS has installed 9 MW of distributed generation systems under the APS Solar Communities program.

Currently, APS has installed 11 MW of DG systems under the APS Solar Communities program.

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

Energy Storage

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

Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and, in certain circumstances, be used to defer certain traditional infrastructure investments.

Energy storage can also aid in integrating higher levels of renewables 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 benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid.

We are preparing for additional energy storage in the future.

In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery.

Service under the agreement was scheduled to begin in 2021;

however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date.

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

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

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

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 expected to be in service by June 2022.

Additionally, in February 2019, APS signed two 20-year power purchase agreements (“PPAs”) for energy storage totaling 150 MW.

In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause.

APS has now completed its investigation of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs.

These PPAs were also 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 both agreements is expected to begin in 2022.

We currently plan to install at least 850 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above.

These battery storage facilities are expected to be in service during the summer of 2022.

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 2022 with respect to 100 MW and in 2023 with respect to 50 MW.

As a result of its December 2020 RFPs, as of February 2022, APS has 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 totaling 275 MW solar plus storage resource.

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.

The remaining project was filed in February 2022 for ACC approval and is pending ACC review.

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

APS currently plans to install more than 900 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.

Currently, APS has two RFPs in the market that seek energy storage resources:

(i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites that were not included in the 2018 RFP referenced in the preceding paragraph;

and (ii) an ‘all source’ RFP that solicits both standalone energy storage and renewable energy plus energy storage resources.

Such resources would be expected to be in service during 2023 and 2024.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2021.

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

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

Energy Storage

PPAs - Energy Storage —

Residential Energy Storage 12(a) 3

Total Energy Storage Portfolio

(a) This includes 11.7 MW of APS customer-owned batteries and 0.3 MW of APS-owned residential batteries.

Purchased Power Contracts

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

(See Note 16.) APS continually assesses its need for additional capacity resources to assure system reliability.

In addition, APS has also entered into several power purchase agreements for energy storage.

(See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for details of our energy storage power purchase agreements.)

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

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

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

Purchased Power Capacity — APS’s purchased power capacity under long-term contracts as of December 31, 2021, is summarized in the table below.

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Purchase Agreement (a) Year-round through June 14, 2022 45

Exchange Agreement (b) May 15 to September 15 annually through February 2021 480

Demand Response Agreement (c) Summer seasons through 2025 75

Demand Response Agreement (b) Summer seasons through 2025 75

Tolling Agreement Summer seasons from Summer 2020 through Summer 2025 565

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

Renewable Energy (d) Various 626

Renewable Energy (c) Various 736

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

Energy Storage Various 510

(a) Up to 45 MW of capacity is available;

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

(b) This is a seasonal capacity exchange agreement under which APS receives electricity during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity during the winter season (from October 15 to February 15).

This agreement expired on February 15, 2021.

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

(b) The capacity under this agreement is 75 MW for years 2022 through 2025.

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

Current and Future Resources

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

APS’s 2020 peak one-hour demand on its electric system was recorded on July 30, 2020 at 7,660 MW, compared to the 2019 peak of 7,115 MW recorded on August 5, 2019.

APS’s 2021 peak one-hour demand on its electric system was recorded on June 18, 2021, at 7,580 MW, compared to the 2020 peak of 7,660 MW recorded on July 30, 2020.

APS’s reserve margin at the time of the 2021 peak demand, calculated using system load serving capacity, was 15%.

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

In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.

APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.

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

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.

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

The ACC has taken no action on APS’s IRP.

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 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases.

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.

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

In 2015, APS and the CAISO, the operator for the majority of California’s transmission grid, signed an agreement for APS to begin participation in the Energy Imbalance Market (“EIM”).

APS’s participation in the EIM began on October 1, 2016.

The EIM allows for rebalancing supply and demand in 15-minute blocks, with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks.

Participation in the EIM continues to be an effective tool for creating savings for APS’s customers from the real-time, voluntary market.

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

In 2016, APS began to participate in the Western 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.

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On July 30, 2020, the ACC Staff issued final draft energy rules, which proposed 100% of retail kWh sales from clean energy resources by the end of 2050.

Nuclear is defined as a clean energy resource.

The proposed rules also require 50% of retail energy served be renewable by the end of 2035.

On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting.

This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding.

On October 29, 2020, the ACC approved an amendment that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032;

and 100% by 2050.

The ACC also approved an amendment which will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% must be derived from customer-owned or customer-leased distributed storage.

Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan.

On November 13, 2020, the ACC approved a final draft energy rules package, and additional procedural steps in the rulemaking process are required to be completed before the rules may take effect.

APS cannot predict the outcome of this matter.

Nuclear power was defined as a clean energy resource.

The proposed rules also required 50% of retail energy served be renewable by the end of 2035.

On November 13, 2020, the ACC approved a final draft energy rules package which required additional procedural steps in the rulemaking process.

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:

50% reduction by December 31, 2032;

65% reduction by December 31, 2040;

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

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

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

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

See Note 4 for additional information related to these energy rules.

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This distributed energy requirement is 30% of the overall RES requirement of 12% in 2022.

On September 23, 2020, the ACC approved the 2020 RES Implementation Plan.

On July 1, 2020, APS filed its 2021 RES Implementation Plan.

On June 7, 2021, the ACC approved the 2021 RES Implementation Plan.

2021, APS filed its 2022 RES Implementation Plan and amended it on December 9, 2021.

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

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Gillespie Maricopa County, AZ 2013 30 15

Aragonne Mesa (b) Santa Rosa, NM 2022 20 90 110

CO Bar Solar A Coconino County, AZ 2023 18 80

CO Bar Solar B Coconino County, AZ 2023 18 80

Mesquite Solar 5 Tonopah, AZ 2023 20 60

Aragonne Mesa Santa Rosa, NM 2022 20 200

High Lonesome Mountainair, NM 2009 30 100

Perrin Ranch Wind Williams, AZ 2012 25 99

Chevelon Butte Winslow, AZ 2023 20 238

Salton Sea Imperial County, CA 2006 23 10

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

(b) Includes 90 MW wind power purchase agreement that was in operation until 2021.

As a result of a power purchase agreement executed in September 2020, this will be decommissioned in 2021 and rebuilt in the same year, together with an additional 110 MW, for a total of 200 MW.

Distributed generation is produced in DC and is converted to AC for reporting purposes.

APS also issued two RFPs in September 2019.

The first RFP sought competitive proposals for up to 150 MW of APS-owned solar resources.

This solar generation will be designed with the flexibility to add energy storage as a future option.

Negotiations pursuant to this RFP are ongoing, with results expected in the first quarter of 2021 and project in-service expected by the end of 2022.

A second RFP requested up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022.

As a result of this RFP, APS executed a 200 MW power purchase agreement for a wind resource that is expected to be in service in the fourth quarter of 2021.

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

DG is produced in DC and is converted to AC for reporting purposes.

In September 2019, APS issued an RFP that requested up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022.

As a result of this RFP, APS executed a 200 MW PPA for a wind resource that went into service in January 2022.

In December 2020, APS issued two additional RFPs:

one to acquire both renewable energy and additional peaking capacity resources, and the other to install more battery energy storage at two existing APS solar plants.

(i) a battery storage RFP for projects to be located at two AZ Sun sites;

and (ii) an all source RFP that solicited resources to meet our clean energy needs and capacity to maintain system reliability, and that was later amended to include a request for 150 MW of solar resources to be developed on APS property and owned by APS (collectively, the “December 2020 RFPs”).

As a result of the all source RFP, APS executed a PPA in October 2021 for a 238 MW wind resource to be in service by June 2023, and also executed an engineering, procurement, and construction contract in November 2021 for a 150 MW solar resource to be owned by APS and in service in early 2023.

APS continues to negotiate contracts for additional resources to be in service in 2024 in connection with the all source RFP.

Once it secures those

important resources and closes out the December 2020 RFPs, APS intends to issue its next all source RFP to address resource needs for 2025 and beyond.

Demand Side Management

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

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

APS achieved the 22% EES in 2021.

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The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.

One of these considerations was whether various aspects of a deregulated market, including setting

utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.

One of these considerations was whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.

On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.

The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.

The ACC opened a docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.

A series of workshops in this docket were held in 2014 and another in February of 2015.

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

An ACC special open meeting workshop was held on December 3, 2018.

No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff.

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

Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019.

ACC Commissioners submitted additional questions regarding this matter.

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

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

The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules.

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

The ACC Commissioners are continuing to explore the retail electric competition rules.

The ACC continues to discuss matters related to retail electric competition, including the potential for additional buy-through programs or other pilot programs.

At the same time, the Arizona legislature is considering a bill that would nullify, if approved, a 20-year-old electric deregulation law that has been in place since

The bill has several procedural steps in the legislative process before becoming law.

APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona.

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 his 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.

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

APS cannot predict the outcome of these future activities.

FERC regulates rates for wholesale power sales and transmission services.

(See Note 4 for information regarding APS’s transmission rates.) During 2020, approximately 4.4% of APS’s electric operating revenues resulted from such sales and services.

See Note 4 for information regarding APS’s transmission rates.

During 2021, approximately 7.6% of APS’s electric operating revenues resulted from such sales and services.

APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements.

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

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

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

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.

new customer sited technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions.

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

Environmental Matters

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Legislative Initiatives.

There have been no recent successful attempts by Congress to pass legislation that would regulate GHG emissions, and it is unclear at this time whether climate-change related legislation originating from the 117th Congress will be considered in the Senate and then signed into law by President Biden.

There have been no recent successful attempts by Congress to pass legislation that would regulate GHG emissions, and it is unclear at this time whether legislation regulating or limiting utility-sector GHG emissions under consideration in the 117th Congress will become law.

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

These factors include the terms of the legislation with regard to allowed GHG emissions;

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

the cost to reduce emissions;

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In addition to federal legislative initiatives, state-specific initiatives may also impact our business.

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

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.

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As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants.

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

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

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.

The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S.

On January 19, 2021, the U.S.

Court of Appeals for the D.C.

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That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP.

While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the

Clean Air Act, Clean Water Act, Endangered Species Act, Resource Conservation and Recovery Act (“RCRA”), Superfund, the Navajo Nation, and water supplies for our power plants.

On October 29, 2021, the U.S.

Supreme Court announced that it was accepting judicial review of the January D.C.

Circuit decision vacating the ACE regulations.

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.

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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 4 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.

See Note 4 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.

(See “Four Corners — 4CA Matter” in Note 11 for a discussion of the NTEC purchase.) 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.

See “Four Corners — 4CA Matter” in Note 11 for a discussion of the NTEC purchase.

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:

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Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations.

On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments;

such disposal units must close as soon as technically feasible, but no later than April 22, 2021.

On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments by April 11, 2021 at the latest.

All APS disposal units subject to these closure requirements were closed as of April 11, 2021.

• On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure.

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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 we anticipate receiving a proposed decision with respect to the Cholla facility in 2022.

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.

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

In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by October 31, 2020.

APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2021.

As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action.

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

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

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

however, additional investigations and engineering analyses that will support the remedy selection are still underway.

In addition, APS 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.

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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 effluent limitation guidelines.

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

At this time, APS’s National Pollution 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.

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.

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Ozone National Ambient Air Quality Standards.

On October 1, 2015, EPA finalized revisions to the primary ground-level ozone national ambient air quality standards (“NAAQS”) at a level of 70 parts per billion (“ppb”).

On October 1, 2015, EPA finalized revisions to the primary ground-level ozone NAAQS at a level of 70 parts per billion (“ppb”).

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

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

While EPA took action designating attainment and unclassifiable areas on November 6, 2017, the Agency’s final action

designating non-attainment areas was not issued until April 30, 2018.

At that time, EPA designated the geographic areas containing Yuma and Phoenix, Arizona as in non-attainment with the 2015 70 ppb ozone NAAQS.

While EPA took action designating attainment and unclassifiable areas on November 6, 2017, the Agency’s final action designating non-attainment areas was not issued until April 30, 2018.

At that time, EPA designated the geographic areas containing Yuma and

Phoenix, Arizona as in non-attainment with the 2015 70 ppb ozone NAAQS.

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

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

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

PRPs may be strictly, and often are jointly and severally, liable for clean-up.

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

PRPs may be strictly, jointly, and severally liable for clean-up.

On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona.

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Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2022.

We estimate that our costs related to this investigation and study will be approximately $3 million.

We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time, expenditures related to this matter cannot be reasonably estimated.

APS estimates that its cost related to this investigation and study is approximately $3 million.

APS anticipates incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, 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.

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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 service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants.

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 service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants.

We are unable to predict the outcome of these matters;

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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 effluent limitation guidelines 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.

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.

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Court of Appeals for the Ninth Circuit.

We cannot predict the outcome of these appeal proceedings and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

As of November 11, 2021, the parties to this lawsuit, including APS, reached a tentative agreement to settle this matter.

Review of this agreement, including public commenting, is currently pending with the EPA.

Notwithstanding this tentative agreement, we cannot predict the outcome of these appeal proceedings, including further settlement discussions, and, if settlement efforts fail and the appeal is eventually successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

Assured supplies of water are important for APS’s generating plants.

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The Four Corners region, in which Four Corners is located, has historically experienced drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area.

However, during the past 12 months the region has received snowfall and precipitation sufficient to recover the Navajo Reservoir to an optimum operating level, reducing the probability of shortage in future years.

Although the watershed and reservoirs are in a good condition at this time, APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future drought conditions that could have an impact on operations of its plants.

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At this time, the lower court proceedings in the Gila River adjudication are in the process of determining the specific hydro-geologic testing protocols for determining which groundwater wells located outside of the subflow zone of the Gila River should be subject to the adjudication court’s jurisdiction.

A hearing to determine this jurisdictional test question was held in March of 2018 in front of a special master, and a draft decision based on the evidence heard during that hearing was issued on May 17, 2018.

A hearing to determine this jurisdictional test question was held in March 2018 in front of a special master, and a draft decision based on the evidence heard during that hearing was issued on May 17, 2018.

The decision of the special master, which was finalized on November 14, 2018, but which is subject to further review by the trial court judge, accepts the proposed hydro-geologic testing protocols supported by APS and other industrial users of groundwater.

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APS’s claims dispute the court’s jurisdiction over its groundwater rights.

Alternatively, APS seeks confirmation of such rights.

Alternatively, APS seeks confirmation of such

No trial or pretrial proceedings have been scheduled for adjudication of APS’s water right claims.

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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.

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.

In 2014, BCE formed a 50/50 joint venture 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 states that comprise the Western Electricity Coordinating Council, 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.

As of December 31, 2020, BCE had total assets of approximately $27 million.

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.

Both wind farms deliver power under long-term power purchase agreements.

BCE 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’s short-term goal is to prudently realize the value of its existing investments.

As of December 31, 2020, El Dorado had total assets of approximately $16 million.

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.

Other Information

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

BCE and 4CA are incorporated in Delaware.

Additional information for each of these companies is provided below:

Principal Executive Office

Address Year of

Incorporation Approximate

December 31, 2020

Pinnacle West 400 North Fifth Street

Phoenix, AZ 85004 1985 88

APS 400 North Fifth Street

Phoenix, AZ 85072-3999 1920 5,933

BCE 400 East Van Buren

Phoenix, AZ 85004 2014 5

El Dorado 400 East Van Buren

Phoenix, AZ 85004 1983 —

4CA 400 North Fifth Street

Phoenix, AZ 85004 2016 —

The APS number includes employees at jointly-owned generating facilities (approximately 2,304 employees) for which APS serves as the generating facility manager.

Approximately 1,263 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.

Human Capital

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We believe the strength of our employees is one of the significant contributors to our Company’s success.

Human capital measures and objectives that the Company focuses on in managing its business include the safety of its employees, diversity and inclusion, succession planning, hiring and retention of talent, compensation and benefits and employee engagement.

Human capital measures and objectives that the Company focuses on in retaining its talent and managing its business include the safety of our employees, career development, diversity, equity and inclusion, succession planning, hiring, voluntary turnover, compensation, benefits, employee experience and engagement.

The health, well-being and safety of our employees, customers and communities is our top priority.

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By the middle of March 2020, we successfully transitioned all of our employees to remote work unless they were essential workers that needed to remain onsite.

These efforts have resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations.

We also established COVID-19 safety protocols, social distancing practices including limiting one employee per vehicle and offering virtual options whenever possible.

We identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue arose.

Additionally, efforts to ensure the health and safety of our employees resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations.

We also established COVID-19 safety protocols, social distancing practices and offered virtual options whenever possible.

The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic.

Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the

As a result of these efforts, we have been able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers and communities.

Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace.

As a result of these efforts, we were able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being, and safety of our employees.

Employee Safety

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As we continue to improve our safety performance, our ultimate goal remains serious injury reduction.

Our employees are expected to do the right thing and empowered to speak up when there are better or safer ways of doing business, including stopping work to reassess or improve safety.

Our employees are expected to do the right thing and are empowered to speak up when there are better or safer ways of doing

business, including stopping work to reassess or improve safety.

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

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Our Executive Diversity & Inclusion Council leads this commitment with an emphasis on diversity among employees, in the workplace and through our community involvement, as well as an increased focus on attracting and retaining diverse talent.

This focus extends to individual business units in the Company, which report on the diversity of their team during management review meetings to build awareness and address gaps of workforce diversity.

This focus extends to individual business units in the Company, which report on the diversity of their teams during management review meetings to build awareness and address gaps of workforce diversity.

Our efforts to support and empower employees include a commitment to full inclusion.

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

At the end of 2020, 36% of external hires were ethnically diverse, 36% were female and 18% were veterans.

During 2021, 44% of external hires were ethnically or racially diverse, 37% were female and 10% were veterans.

Additionally, as of December 31, 2021, 33% of our employees are ethnically or racially diverse, 25% are female and 16% are veterans.

Also, as of December 31, 2021, 40% of the Company’s officers are female.

In 2021, APS received the 2021 Inclusive Workplace Award, a joint award presented by the Diversity Leadership Alliance and the Arizona Society of Human Resources Management.

The award recognizes APS as an Arizona corporation that leads by example, creating an inclusive environment in which employees can be their genuine, authentic selves and partners on community outreach efforts and support.

Succession Planning

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

Talent Strategy

Talent Strategy and Development

We place significant focus on attracting and developing a skilled workforce.

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Our employees have access to a wide variety of training and development opportunities, including leadership academies, rotational programs, mentoring programs, industry certifications and loaned executive programs.

In 2021, we graduated 84 employees from our leadership academies.

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.

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

In 2020, we hosted 56 summer interns from 11 different universities 100% virtually with a diversity rate of 52%.

In 2021, we hosted 67 summer interns with a diversity rate of 68%.

Total Rewards Strategy

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Our employees are important to the success and future of our organization and our customers’ experiences.

At the Company, our pay and benefits, along with retirement, recognition, time off, career development and wellbeing, make up our Total Rewards program.

It is an important part of the employee experience at the Company and supports personal wellbeing and professional satisfaction.

At the Company, our pay and benefits, along with retirement, recognition, time off, career development and well-being, make up our Total Rewards program.

It is an important part of the employee experience at the Company and supports personal well-being and professional satisfaction.

We are committed to providing programs that matter to our employees throughout various life and career phases.

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

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.

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

Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.

As of December 31, 2021, BCE had total assets of approximately $27 million.

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”).

Creek achieved commercial operation in May 2020 and 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.

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’s short-term goal is to prudently realize the value of its existing investments.

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

As of December 31, 2021, El Dorado has contributed approximately $10 million to the Energy Impact Partners fund.

Additionally, El Dorado committed to a $25 million investment in 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.

The investment will be made by El Dorado as investments are selected by the invisionAZ Fund.

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

BCE and 4CA are incorporated in Delaware.

Additional information for each of these companies is provided below:

Principal Executive Office

Address Year of

Incorporation Approximate

December 31, 2021

Pinnacle West 400 North Fifth Street

Phoenix, AZ 85004 1985 91

APS 400 North Fifth Street

Phoenix, AZ 85072-3999 1920 5,776

BCE 400 East Van Buren Street

Phoenix, AZ 85004 2014 5

El Dorado 400 East Van Buren Street

Phoenix, AZ 85004 1983 —

4CA 400 East Van Buren Street

Phoenix, AZ 85004 2016 —

The APS number includes employees at jointly-owned generating facilities (approximately 2,158 employees) for which APS serves as the generating facility manager.

Approximately 1,229 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.

WHERE TO FIND MORE INFORMATION

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

What changed 10-K

Item 1. Business