FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as ~~"estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume," "project"~~“estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” “anticipate,” “goal,” “seek,” “strategy,” “likely,” “should,” “will,” “could,” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

•the potential effects of the continued COVID-19 pandemic, including, but not limited to, demand for energy, economic growth, our employees and contractors, supply chain, expenses, capital markets, capital projects, operations and maintenance activities, uncollectable accounts, liquidity, cash flows or other unpredictable events;

•our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

•variations in demand for electricity, including those due to weather, seasonality, the general economy or social conditions, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;

•power plant and transmission system performance and outages;

•competition in retail and wholesale power markets;

•regulatory and judicial decisions, developments and proceedings;

•new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory and energy policy, nuclear plant operations and potential deregulation of retail electric markets;

•fuel and water supply availability;

•our ability to achieve timely and adequate rate recovery of our costs through our rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investment;

•our ability to meet renewable energy and energy efficiency mandates and recover related costs;

•the ability of APS to achieve its clean energy goals (including a goal by 2050 of 100% clean, carbon-free electricity) and, if these goals are achieved, the impact of such achievement on APS, its customers, and its business, financial condition and results of operations;

•risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

•current and future economic conditions in Arizona, including in real estate markets;

•the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events or similar occurrences;

•the development of new technologies which may affect electric sales or delivery;

•the cost of debt and equity capital and the ability to access capital markets when required;

•environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;

•volatile fuel and purchased power costs;

•the investment performance of the assets of our nuclear decommissioning ~~trust,~~trusts, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

•the liquidity of wholesale power markets and the use of derivative contracts in our business;

•potential shortfalls in insurance coverage;

•new accounting requirements or new interpretations of existing requirements;

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•generation, transmission and distribution facility and system conditions and operating costs;

•the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;

•the willingness or ability of our counterparties, power plant participants and power plant ~~land owners~~landowners to meet contractual or other obligations or ~~continue or discontinue~~extend the rights for continued power plant ~~operations consistent with our corporate interests;~~operations; and

•restrictions on dividends or other provisions in our credit agreements and ACC orders.

These and other factors are discussed in the Risk Factors described in Item 1A of this report, and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this

report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

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PART I

ITEM 1. BUSINESS

Pinnacle West

Pinnacle West is a holding company that conducts business through its subsidiaries. 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. Additional information related to these subsidiaries is provided later in this report.

Our reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

APS currently provides electric service to approximately 1.3 million customers. We own or lease ~~6,316~~6,321 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. During ~~2019,~~2020, no single purchaser or user of energy accounted for more than ~~1.7%~~1.4% of our electric revenues.

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

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Energy Sources and Resource Planning

To serve its customers, APS obtains power through its various generation stations and through purchased power agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’s sources of energy by type used to supply energy to Native Load customers during ~~2019~~2020 were as follows:

* ~~When including APS’s historical~~Renewables include energy ~~efficiency and~~from wind, solar, geothermal, biomass, distributed generation ~~energy contributions, the~~and solar power purchase agreements.

The share of ~~our customers’~~APS’s energy supply being derived from clean resources is ~~51%~~50%.

** Purchased Power includes renewables from 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 with grid-scale renewables providers and distributed generation.~~

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

Clean Energy Focus Initiatives

APS has undertaken a number of initiatives to ~~address emission concerns,~~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 ~~recently~~ announced its Clean Energy Commitment, a three-pronged approach aimed at ultimately eliminating carbon-emitting resources from its electric generation resource portfolio.

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APS’s ~~Clean Energy Commitment consists~~clean energy goals consist of three ~~parts. First, APS announced an aspirational~~parts:

•a 2050 goal to ~~generate electricity with zero-carbon emissions by 2050. Second, APS announced~~ provide 100% clean, carbon-free electricity;

•a ~~nearer-term~~ 2030 target of achieving a resource mix that is 65% clean energy, with 45% of ~~APS's~~the generation portfolio coming from renewable ~~energy. Third, APS committed~~energy; and

•a commitment to

~~eliminate~~ end APS’s use of coal-fired generation ~~from its portfolio of electricity generating resources~~ 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; increasing clean energy resources, including renewables; developing energy storage; ~~cease buying coal-generation;~~ceasing the use of coal-generated electricity; managing demand with a modern interactive grid; promoting customer technology and energy efficiency; and optimizing regional resources. (See Item 7, ~~"Management's~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operation"~~Operation” for additional information about ~~our~~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~~APS’s operations. Among other resiliency strategies, APS anticipates increasing investments in a modern and more flexible electricity grid with advanced distribution technologies. ~~Moreover,~~ 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 prepares an annual inventory of GHG emissions from its operations. For ~~APS's~~APS’s operations involving fossil-fuel electricity generation and electricity transmission and distribution, ~~APS's~~APS’s annual GHG inventory is reported to EPA under the EPA GHG Reporting Program. APS also voluntarily tracks the full scope of ~~the Company's~~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 ~~Company~~APS operations, such as vehicle use, employee travel, portable generators and facility energy usage. 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~~www.pinnaclewest.com/corporate-responsibility). The report provides information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into or otherwise a part of this report.

Generation Facilities

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

Nuclear

Palo Verde Generating Station — Palo Verde is a 3-unit nuclear power plant located approximately 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and approximately 17% of Unit 2. In addition, APS leases approximately 12.1% of Unit 2, resulting in a 29.1% combined ownership and leasehold interest in that unit. APS has a total entitlement from Palo Verde of 1,146 MW.

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Palo Verde Leases — In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back approximately 42% of its share of Palo Verde Unit 2 and certain common facilities. The leaseback was originally scheduled to expire at the end of 2015 and contained options to renew the leases or to purchase the leased property for fair market value at the end of the lease terms. On July 7, 2014, APS exercised the fixed rate lease renewal options. The exercise of the renewal options resulted in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors. ~~See~~(See Note 1918 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.)

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

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

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

•conversion of uranium concentrates to uranium hexafluoride;

•enrichment of uranium hexafluoride;

•fabrication of fuel assemblies;

•utilization of fuel assemblies in reactors; and

•storage and disposal of spent nuclear fuel.

The Palo Verde participants have contracted for 100% of Palo Verde’s requirements for uranium concentrates through ~~2025~~2027 and ~~30%~~70% through 2028; 100% of Palo Verde’s requirements for conversion services through ~~2025, and 40% through~~ 2030; 100% of Palo Verde’s requirements for enrichment services through ~~2021, 90%~~2026 and 40% for ~~2022, and 80% for 2023 through 2026;~~2027; and 100% of Palo Verde’s requirements for fuel fabrication through 2027.

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. The DOE’s obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the “Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. The DOE had planned to meet its NWPA and Standard Contract disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In June 2008, the DOE submitted its Yucca Mountain construction authorization application to the NRC, but in March 2010, the DOE filed a motion to dismiss with prejudice the Yucca Mountain construction authorization application. Several legal proceedings followed challenging DOE’s withdrawal of its Yucca Mountain construction authorization application and the NRC’s cessation of its review of the Yucca Mountain construction authorization application, which were consolidated into one matter at the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). Following the D.C. Circuit’s August 2013 order, the NRC issued two volumes of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. Publication of these volumes do not signal whether or when the NRC might authorize construction of the repository. APS is directly involved in legal proceedings related to the

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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"~~Claims”) for damages incurred due to the DOE’s breach of the Standard Contract. The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded damages to APS and the Palo Verde participants for costs incurred through December 2006.

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the 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. 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, ~~2019.~~2022.

APS has submitted and received payment for ~~five~~six claims pursuant to the terms of the August 18, 2014 settlement agreement, for ~~five~~six separate time periods during July 1, 2011 through June 30, ~~2018.~~2019. The DOE has paid ~~$84.3~~$99.7 million for these claims (APS’s share is ~~$24.5~~$29 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. ~~APS's~~APS’s next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on ~~October 31, 2019~~November 2, 2020 in the amount of ~~$16 million (APS's share is $4.7 million). On February 11, 2020, the DOE approved a payment of $15.4~~$12.2 million (APS’s share is ~~$4.5~~$3.6 million).

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

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

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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.

Nuclear Decommissioning Costs — APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for decommissioning its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’s ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge (paid by all retail customers taking service from the APS system). Based on current nuclear decommissioning trust asset balances, site specific decommissioning cost studies, anticipated future contributions to the decommissioning trusts, and return projections on the asset portfolios over the expected remaining operating life of the facility, we are on track to meet the current site specific decommissioning costs for Palo Verde at the time the units are expected to be decommissioned. ~~See~~(See Note 2019 for additional information about APS’s nuclear decommissioning trusts.)

Palo Verde Liability and Insurance Matters — See “Palo Verde Generating Station — Nuclear Insurance” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

Natural Gas and Oil Fueled Generating Facilities

APS has six natural gas power plants located throughout Arizona, consisting of Redhawk, located near Palo Verde; Ocotillo, located in Tempe (discussed below); Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; and Yucca, located near Yuma. Several of the units at Yucca run on either gas or oil. APS has two oil-only power plants: Fairview, located in the town of Douglas, Arizona and Yucca GT-4 in Yuma, Arizona. APS owns and operates each of these plants with the exception of one oil-only combustion turbine unit and one oil and gas steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District. APS has a total entitlement from these plants of 3,573 MW. ~~Gas~~A portion of the gas for these plants is financially hedged up to five years in advance of purchasing and ~~the~~that position is converted to a physical gas ~~is generally purchased~~purchase one month prior to delivery. APS has long-term gas transportation agreements with three different companies, some of which are effective through 2027. Fuel oil is acquired under short-term purchases delivered by truck directly to the power plants.

Ocotillo was originally a 330 MW 4-unit gas plant located in ~~the metropolitan Phoenix area.~~Tempe. In early 2014, APS announced a project to modernize the plant, which involved retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines. 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~~“2017 Rate Case ~~Decision"~~Decision”)) and the 2019 Retail Rate Case Filing). The Ocotillo modernization project was completed in 2019.

Coal-Fueled Generating Facilities

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

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West, owned 7% of Units 4 and 5 from July 2016 through July 2018 following its acquisition of El ~~Paso's~~Paso’s interest in these units described below. As part of ~~APS's recently announced~~APS’s Clean Energy Commitment, APS has committed to ~~eliminate~~cease using coal-fired generation ~~from~~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~~“2016 Coal Supply ~~Agreement"~~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~~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~~4CA’s 7% interest in Four Corners. The sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a

period of four years pursuant to a secured interest-bearing promissory note. 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~~NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle ~~West's~~West’s guarantee is secured by a portion of ~~APS's~~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. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also required the approval of the DOI, as did a related federal rights-of-way grant. A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuance by DOI of a record of decision on July 17, 2015 justifying the agency action extending the life of the plant and the adjacent mine.

On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at Four Corners and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019.

Cholla — Cholla was originally a 4-unit coal-fired power plant, which is located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4, and APS ~~operates~~operated that unit for PacifiCorp. On September 11, 2014, APS announced that it would close ~~its 260 MW~~Cholla Unit 2 ~~at Cholla~~ and cease burning coal at ~~Units~~the other APS-owned units (Units 1 and 33) 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~~APS’s plan to retire Unit 2, without expressing any view on the future recoverability of ~~APS's~~APS’s remaining investment in the Unit, which was later addressed in the March 27, 2017 settlement agreement regarding APS's general retail case (the "2017 Settlement Agreement"). (See Note 4 for details related to the resulting regulatory asset and allowed recovery set forth in the 2017 Settlement Agreement.)Unit. APS ~~believes that the environmental benefits~~closed

Table of ~~this proposal are greater in the long-term than the benefits that would have resulted from adding the emissions control equipment. APS closed~~ Contents

Unit 2 on October 1, 2015. Following the closure of Unit 2, APS has a total entitlement from Cholla of 387 MW. In early 2017, EPA

approved a final rule incorporating ~~APS's~~APS’s compromise proposal, which took effect for Cholla on April 26, 2017. In December 2019, PacifiCorp notified APS that it ~~plans~~planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020.

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. The Cholla coal contract runs through 2024. In addition, APS has a coal transportation contract that runs through ~~2020, with the ability to extend the contract annually 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. APS had a total entitlement from the Navajo Plant of 315 MW. The Navajo Plant’s coal requirements were purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Plant was under contract with its coal supplier through 2019, with extension rights through 2026. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that ~~allows~~allowed for decommissioning activities to begin after the plant ceased operations in November 2019.

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

Solar Facilities

APS developed utility scale solar resources through the 170 MW ACC-approved AZ Sun Program, investing approximately $675 million in this program. These facilities are owned by APS and are located in multiple locations throughout Arizona. In addition to the AZ Sun Program, APS developed the 40 MW Red Rock Solar Plant, 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.

APS owns and operates more than thirty small solar systems around the state. Together they have the capacity to produce approximately 4 MW of renewable energy. This fleet of solar systems includes a 3 MW facility located at the Prescott Airport and 1 MW of small solar systems in various locations across Arizona. APS has also developed solar photovoltaic distributed 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 energy systems located within a certain test area in Flagstaff, Arizona. The pilot program is now complete and as part of the 2017 Rate Case Decision, the participants have been transferred to the Solar Partner Program described below. Additionally, APS owns 13 MW of solar photovoltaic systems installed across Arizona through the ACC-approved Schools and Government Program.

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

Program,"” placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The costs for this program have been included in ~~APS's~~APS’s rate base as part of the 2017 Rate Case Decision.

In the 2017 Rate Case Decision, the ACC also approved the ~~"APS~~“APS Solar ~~Communities"~~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. 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 59 MW of distributed generation systems under the APS Solar Communities program.

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, ~~can~~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 ~~this~~the agreement iswas scheduled to begin in ~~2021.~~2021; however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date. 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 ~~our~~its evaluation of the ~~Request for Proposals ("RFP")~~RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. ~~In February 2019, we contracted for the 141 MW and originally anticipated such~~These battery storage facilities ~~could~~are expected to be in service by ~~mid-2020.~~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. ~~The results of the~~APS has now completed its investigation will inform the timing of our utilization and implementation of batteries on our system. Due to the April 2019 event, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements is also dependent on the results of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and ~~requires~~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 ~~from the ACC~~in order to allow for cost recovery ~~of these agreements~~ through the ~~PSA (See Note 4 for details related~~PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to ~~the PSA).~~begin in 2022.

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We currently plan to install at least 850 MW of energy storage by 2025, including the ~~150 MW of~~ energy storage projects under ~~power purchase agreements~~PPAs and AZ Sun retrofits described above. The ~~additional 700 MW of APS-owned~~remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the ~~retrofits associated with our~~market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites ~~as described above, along with current~~that were not included in the 2018 RFP referenced in the preceding paragraph; and ~~future RFPs for~~(ii) an ‘all source’ RFP that solicits both standalone energy storage and ~~solar~~renewable energy plus energy storage ~~projects. Given the April 2019 event, we continue~~resources. Such resources would be expected to ~~evaluate the appropriate timing~~be in service during 2023 and path forward to support the overall capacity goals for our system and associated energy storage requirements. Currently, APS is pursuing an RFP for battery-ready solar resources up to 150 MW with results expected in the first half of 2020.2024.

Purchased Power Contracts

In addition to its own available generating capacity, APS purchases electricity under various arrangements, including long-term contracts and purchases through short-term markets to supplement its owned or leased generation and hedge its energy requirements. A portion of APS’s purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. (See Note ~~17.~~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~~“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Energy ~~Storage"~~Storage” above for details of our energy storage power purchase agreements.)

Purchased Power Capacity — APS’s purchased power capacity under long-term contracts as of December 31, ~~2019~~2020 is summarized in the table below. All capacity values are based on net capacity unless otherwise noted.

Type

Dates Available

Capacity
(MW)

Purchase Agreement (a)

Year-round through June 14, ~~2020~~2022

6045

Exchange Agreement (b)

May 15 to September 15 annually through February 2021

480

Demand Response Agreement (c)

Summer seasons through ~~2024~~2025

2575

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

Tolling Agreement

May 1 through October 31, 2021-2027

463


~~(a)~~	~~Up to 60 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).


~~(c)~~	~~The capacity under this agreement may be increased in 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.~~


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

(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.

(c)The capacity under this agreement is 60 MW in 2021 and 75 MW for years 2022 through 2025.

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

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Current and Future Resources

Current Demand and Reserve Margin

Electric power demand is generally seasonal. In Arizona, demand for power peaks during the hot summer months. APS’s ~~2019~~2020 peak one-hour demand on its electric system was recorded on ~~August 5, 2019~~July 30, 2020 at ~~7,115~~7,660 MW, compared to the ~~2018~~2019 peak of ~~7,320~~7,115 MW recorded on ~~July 24, 2018. The reduction was largely driven by milder peak day weather conditions in~~August 5, 2019. APS’s reserve margin at the time of the ~~2019~~2020 peak demand, calculated using system load serving capacity, was ~~16%~~19%. For ~~2020,~~2021, due to expiring purchased power contracts, APS is procuring market resources to maintain its minimum 15% planning reserve criteria.

Future Resources and Resource Plan

ACC rules require utilities to develop ~~fifteen-year~~15-year Integrated Resource Plans ~~("IRP"~~(“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. 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. On February 20, 2020, the ACC extended the deadline for all utilities to file their ~~IRP’s~~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. The ACC has taken no action on APS’s IRP.

See ~~"Business~~“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Clean Energy Focus ~~Initiatives"~~Initiatives” and ~~"Business~~“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Energy ~~Storage"~~Storage” above for information regarding future plans for energy storage. See ~~"Business~~“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Generation Facilities -— Coal-Fueled Generating ~~Facilities"~~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~~California’s transmission grid, signed an agreement for APS to begin participation in the Energy Imbalance Market (“EIM”). ~~APS's~~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. 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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Energy Modernization Plan

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; 75% by 2040; 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. (See Note 4 for additional information related to these energy rules.)

Renewable Energy Standard

In 2006, the ACC adopted the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement is ~~10%~~11% of retail electric sales in ~~2020~~2021 and increases annually until it reaches 15% in 2025. In APS’s 2009 general retail rate case settlement agreement (the “2009 Settlement Agreement”), APS committed to use its best efforts to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to any existing resources or commitments as of the end of 2008. APS met its settlement commitment in 2015.

A component of the RES is focused on stimulating development of distributed energy systems. Accordingly, under the RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed energy requirement is 30% of the overall RES requirement of ~~10%~~11% in ~~2020.~~2021. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan. On July 1, ~~2019,~~2020, APS filed its ~~2020~~2021 RES Implementation Plan. The following table summarizes the RES requirement standard ~~(not including the additional commitment required by the 2009 Settlement Agreement)~~ and its timing:


	2021	2025
RES (inclusive of distributed energy) as a % of retail electric sales	11%	15%
Percent of RES to be supplied from distributed energy resources	30%	30%

2020 2025
RES (inclusive of distributed energy) as a % of retail electric sales 10% 15%
Percent of RES to be supplied from distributed energy resources 30% 30%

On April 21, 2015, the RES rules were amended to require utilities to report on all eligible renewable resources in their service territory, irrespective of whether the utility owns renewable energy credits associated with such renewable energy. The rules allow the ACC to consider such information in determining whether APS has satisfied the requirements of the RES. ~~See "Energy Modernization Plan" in Note 4 for information regarding an additional renewable energy standards proposal.~~

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Renewable Energy Portfolio. To date, APS has a diverse portfolio of existing and planned renewable resources totaling ~~1,923~~2,106 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, ~~1,828~~1,956 MW are currently in operation and 95150 MW are under contract for development or are under construction. Renewable resources in operation include ~~240~~245 MW of facilities owned by APS, 626 MW of long-term purchased power agreements, and an estimated ~~962~~1,085 MW of customer-sited, third-party owned distributed energy resources.

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~~“Energy Sources and Resource Planning -— Generation Facilities -— Solar ~~Facilities"~~Facilities” above for information regarding APS-owned solar facilities.

The following table summarizes APS’s renewable energy sources currently in operation and under development as of December 31, ~~2019.~~2020. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

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	Location	Actual/ Target Commercial Operation Date	Term (Years)	Net Capacity In Operation (MW AC)	Net Capacity Planned/Under Development (MW AC)
APS Owned
Solar:
AZ Sun Program:
Paloma	Gila Bend, AZ	2011		17
Cotton Center	Gila Bend, AZ	2011		17
Hyder Phase 1	Hyder, AZ	2011		11
Hyder Phase 2	Hyder, AZ	2012		5
Chino Valley	Chino Valley, AZ	2012		19
Hyder II	Hyder, AZ	2013		14
Foothills	Yuma, AZ	2013		35
Gila Bend	Gila Bend, AZ	2014		32
Luke AFB	Glendale, AZ	2015		10
Desert Star	Buckeye, AZ	2015		10
Subtotal AZ Sun Program				170	—
Multiple Facilities	AZ	Various		4
Red Rock	Red Rock, AZ	2016		40
Distributed Energy:
APS Owned (a)	AZ	Various		31
Total APS Owned				245	—
Purchased Power Agreements
Solar:
Solana	Gila Bend, AZ	2013	30	250
RE Ajo	Ajo, AZ	2011	25	5
Sun E AZ 1	Prescott, AZ	2011	30	10
Saddle Mountain	Tonopah, AZ	2012	30	15
Badger	Tonopah, AZ	2013	30	15
Gillespie	Maricopa County, AZ	2013	30	15
Wind:
Aragonne Mesa (b)	Santa Rosa, NM	2022	20	90	110
High Lonesome	Mountainair, NM	2009	30	100
Perrin Ranch Wind	Williams, AZ	2012	25	99
Geothermal:
Salton Sea	Imperial County, CA	2006	23	10
Biomass:
Snowflake	Snowflake, AZ	2008	15	14
Biogas:
NW Regional Landfill	Surprise, AZ	2012	20	3
Total Purchased Power Agreements				626	110
Distributed Energy
Solar (c)
Third-party Owned	AZ	Various		1,052	40
Agreement 1	Bagdad, AZ	2011	25	15
Agreement 2	AZ	2011-2012	20-21	18
Total Distributed Energy				1,085	40
Total Renewable Portfolio				1,956	150

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Location
Actual/
Target
Commercial
Operation
Date

Term
(Years)

Net
Capacity
In Operation
(MW AC)

Net Capacity
Planned/Under
Development
(MW AC)

APS Owned

Solar:

AZ Sun Program:

Paloma Gila Bend, AZ 2011
17

Cotton Center Gila Bend, AZ 2011
17

Hyder Phase 1 Hyder, AZ 2011
11

Hyder Phase 2 Hyder, AZ 2012
5

Chino Valley Chino Valley, AZ 2012
19

Hyder II Hyder, AZ 2013
14

Foothills Yuma, AZ 2013
35

Gila Bend Gila Bend, AZ 2014
32

Luke AFB Glendale, AZ 2015 10

Desert Star Buckeye, AZ 2015 10

Subtotal AZ Sun Program
170
—

Multiple Facilities AZ Various
4

Red Rock Red Rock, AZ 2016 40

Distributed Energy:

APS Owned (a) AZ Various
26

Total APS Owned
240
—

Purchased Power Agreements

Solar:

Solana Gila Bend, AZ 2013 30
250

RE Ajo Ajo, AZ 2011 25
5

Sun E AZ 1 Prescott, AZ 2011 30
10

Saddle Mountain Tonopah, AZ 2012 30
15

Badger Tonopah, AZ 2013 30
15

Gillespie Maricopa County, AZ 2013 30
15

Solar + Energy Storage:
First Solar Arlington, AZ 2021 15
50

Wind:

Aragonne Mesa Santa Rosa, NM 2006 20
90

High Lonesome Mountainair, NM 2009 30
100

Perrin Ranch Wind Williams, AZ 2012 25
99

Geothermal:

Salton Sea Imperial County, CA 2006 23
10

Biomass:

Snowflake Snowflake, AZ 2008 15
14

Biogas:

NW Regional Landfill Surprise, AZ 2012 20
3

Total Purchased Power Agreements
626
50

Distributed Energy

Solar (b)

Third-party Owned AZ Various
929
45

Agreement 1 Bagdad, AZ 2011 25
15

Agreement 2 AZ 2011-2012 20-21
18

Total Distributed Energy
962
45

Total Renewable Portfolio
1,828
95


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


~~(b)~~	~~Includes rooftop solar facilities owned by third parties. Distributed generation is produced in DC and is converted to AC for reporting purposes.~~

(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.

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

Demand Side Management

~~In December 2009,~~On January 1, 2011, Arizona regulators ~~placed~~adopted an ~~increased focus on~~EES of 22% cumulative annual energy savings by 2020 to increase energy efficiency and other demand side management programs ~~to encourage~~encouraging customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. ~~The ACC initiated its Energy Efficiency rulemaking, with a proposed~~APS achieved the 22% EES ~~of 22% cumulative annual energy savings by~~in 2020. ~~This standard was adopted and became effective on January 1, 2011. This standard will likely impact Arizona’s future energy resource needs.~~ (See Note 4 for information regarding energy efficiency, other DSM obligations and ~~other demand side management obligations).~~

the Energy Modernization Plan.)

Competitive Environment and Regulatory Oversight

Retail

The ACC regulates APS’s retail electric rates and its issuance of securities. The ACC must also approve any significant transfer or encumbrance of APS’s property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates. (See Note 4 for information regarding ~~ACC's~~ACC’s regulation of ~~APS's~~APS’s retail electric rates.)

APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements. This practice is becoming more popular with customers installing or having installed products such as rooftop solar panels to meet or supplement their energy needs.

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. 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

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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.

two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC ~~staff~~Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC ~~has scheduled~~held a workshop ~~for~~on February 25-26, 2020 ~~for~~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. 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.

Wholesale

FERC regulates rates for wholesale power sales and transmission services. (See Note 4 for information regarding APS’s transmission rates.) During ~~2019,~~2020, approximately ~~5.3%~~4.4% of APS’s electric operating revenues resulted from such sales and services. APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS hedges both electricity and ~~fuels.~~natural gas. The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

Transmission and Delivery

APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and clean energy development. The capital expenditures table presented in the ~~"Liquidity~~“Liquidity and Capital ~~Resources"~~Resources” section of ~~Management's~~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. APS is also working to establish and expand advanced grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better manage their energy usage, minimize system outage durations and frequency, enable customer choice for

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

Environmental Matters

Climate Change

~~Climate Change~~

Legislative Initiatives. There have been no recent successful attempts by Congress to pass legislation that would regulate GHG emissions, and it is unclear at this time whether ~~pending~~ climate-change related legislation inoriginating from the ~~116th~~117th Congress will be considered in the Senate and then signed into law by President ~~Trump.~~Biden. 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, ~~and~~ enacted, and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“~~CO2”~~CO2”) equivalent emitted.

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. 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. The first phase of the program, which applies to, among other entities, importers of electricity, commenced on January 1, 2013. Under the program, entities selling electricity into California, including APS, must hold carbon allowances to cover GHG emissions associated with electricity sales into California from outside the state. APS is authorized to recover the cost of these carbon allowances through the PSA.

Regulatory Initiatives. In 2009, EPA determined that GHG emissions endanger public health and welfare. As a result of this “endangerment finding,” EPA determined that the Clean Air Act required new regulatory requirements for new and modified major GHG emitting sources, including power plants. APS will generally be required to consider the impact of GHG emissions as part of its traditional New Source Review ~~("NSR"~~(“NSR”) 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~~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 ~~those~~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.~~

~~The~~review and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations ~~are based upon measures that can be implemented~~and remanded them back to ~~improve the heat rate of steam-electric~~EPA to develop new existing power ~~plants, specifically coal-fired EGUs. In contrast~~plant carbon regulations consistent with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions (e.g., the Navajo Nation) with three years to develop plans establishing source-specific standards of performance based upon applicationcourt’s ruling. That ruling endorsed an expansive view of the ~~ACE rule’s heat-rate improvement emission guidelines.~~federal Clean Air Act consistent with EPA’s 2015 CPP. While ~~corresponding NSR reform regulations were proposed as part of EPA’s initial ACE proposal,~~ the ~~finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs~~Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the ~~near future.~~

WeClean Air Act, we cannot at this time predict the outcome of ~~EPA's regulatory actions repealing~~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 ~~replacing~~other rules or matters involving the ~~CPP. Various state governments, industry organizations,~~

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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. The financial impact of complying with current and future environmental ~~and public-health public interest groups have filed lawsuits~~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 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 ~~D.C. Circuit challenging the legality of EPA’s action, both, in repealing the CPP and issuing the ACE regulations. In addition,~~plants as well as other costs related to ~~the extent that the ACE regulations go into effect as finalized,~~early retirement, but cannot predict whether it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.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-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.

~~under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close~~closure of Cholla Unit 2 ~~and cease burning~~in 2015, APS has committed to ceasing coal atcombustion within Units 1 and 3 by April 2025.PacifiCorp retired Cholla Unit 4 at the ~~mid-2020s.~~end of 2020. (See ~~"Cholla"~~“Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

Four Corners. Based on EPA’s final standards, ~~APS's~~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~~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~~“Four Corners -— 4CA ~~Matter"~~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. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the ~~Resource Conservation and Recovery Act ("RCRA")~~RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment ~~that is contaminating groundwater above a regulated constituent’s groundwater protection standard~~ to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed ~~"forced closure"~~“forced closure” or ~~"closure~~“closure for ~~cause"~~cause” of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

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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. 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, 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.

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

•Based on an August 21, 2018 D.C. 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 ~~November 4, 2019,~~July 29, 2020, EPA ~~proposed that all~~took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface ~~impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater,~~impoundments; such disposal units must ~~cease operation and initiate closure by August 31, 2020 (with an optional three-month extension~~close as ~~needed for the completion of alternative disposal capacity).~~soon as technically feasible, but no later than April 22, 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.Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations.EPA’s July 29, 2020 final regulation adopted this proposal ~~regarding~~and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would ~~require express~~allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA ~~authorization for such facilities~~on November 30, 2020 and is currently pending. This application will be subject to ~~continue operating their CCR disposal units under alternative closure.~~public comment and, potentially, judicial review.

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final ~~action.~~ 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.

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 ~~$22~~$27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately ~~$15~~$16 million.The Navajo Plant ~~currently disposes~~disposed of CCR only in a dry landfill storage area.To comply with the CCR rule for the Navajo Plant, ~~APS's~~APS’s share of incremental costs iswas approximately $1 million, which has been incurred.Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

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As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must ~~cease~~have ceased operating and ~~initiate~~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-2020.~~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. 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. 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.

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 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. ~~In addition,~~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. Nonetheless, on ~~November 22, 2019,~~October 13, 2020, EPA published a ~~proposed~~final rule relaxing ~~the~~these “zero discharge” limitations for ~~bottom-ash~~bottom ash handling water and allowing for approximately 10% of such wastewater to be discharged (on a volumetric, 30-day rolling average basis) ~~subject~~under limited power plant operating scenarios. At this time, APS is pursuing a modification to ~~best-professional judgment effluent limits.~~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 ~~rulemaking proceeding. Nonetheless, we expect that compliance with the resulting limitations will be required in connection with National Pollution Discharge Elimination System ("NPDES") discharge~~ permit ~~renewals at Four Corners (see "Four Corners National Pollutant Discharge Elimination System Permit," below, for more details). For the current NPDES~~modification proceeding, including any public commenting or permit ~~issued to Four Corners, which is subject to an~~ appeal by various environmental groups, the plant must comply with the existing “zero discharge” effluent limitation guidelines for bottom-ash transport wastewater by December 31, 2023. If those guidelines are changed, it is unclear when Four Corners would need to demonstrate compliance with any updated or revised standards.procedures. The Cholla ~~and the Navajo Plant do~~facility does not require NPDES permitting.

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”). Further, on December 23, 2020, EPA issued a final regulation retaining the current primary NAAQS for ozone, following a required scientific review process. With ozone standards becoming more stringent, our fossil generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas. EPA was expected to designate attainment and nonattainment areas relative to the new 70 ppb standard by October 1, 2017. While EPA took action designating attainment and unclassifiable areas on November 6, 2017, the ~~Agency's~~Agency’s final action

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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~~APS’s natural gas-fired EGUs are located in these jurisdictions. Areas of Arizona and the Navajo Nation where the remainder of ~~APS's~~APS’s fossil-fuel fired EGU fleet is located were designated as in attainment. 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. APS will continue to monitor these standards as they are implemented within the jurisdictions affecting APS.

Superfund-Related Matters. The Comprehensive Environmental Response Compensation and Liability Act ~~("CERCLA"~~(“CERCLA” or ~~"Superfund"~~“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”). PRPs may be strictly, and often are 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"~~(“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("(“RI/~~FS"~~FS”) ~~for OU3.~~. 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 induring the ~~spring~~first or ~~summer~~second quarter of ~~2020.~~ 2021.We estimate that our costs related to this investigation and study will be approximately $2$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.

On August 6, 2013, the Roosevelt Irrigation District ~~("RID"~~(“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. As part of a 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. 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~~APS’s exposure or risk related to these matters.

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

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.

~~Federal Agency Environmental Lawsuit Related to Four Corners~~

See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Four Corners" above for information regarding the lawsuit against OSM and other federal agencies in connection with their issuance of approvals necessary to extend the operation of Four Corners and the adjacent mine.

Four Corners National Pollutant Discharge Elimination System ~~("NPDES")~~ Permit

~~EPA EAB, based~~Based upon a November 1, 2019 filing by several environmental ~~groups.~~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. 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. We cannot predict the outcome of ~~this review~~these appeal proceedings and, if such appeal is successful, whether ~~the review~~that outcome will have a material impact on our financial position, results of operations, or cash flows.

~~Navajo Nation Environmental Issues~~

Four Corners and the Navajo Plant are located on the Navajo Reservation and are held under rights of way granted by the federal government, as well as leases from the Navajo Nation. See “Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities” above for additional information regarding these plants.

~~In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking~~ Water Act, and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners and the Navajo Plant. On October 17, 1995, the Four Corners participants and the Navajo Plant participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Plant. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.

In April 2000, the Navajo Nation Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. On July 12, 2000, the Four Corners participants and the Navajo Plant participants each filed a petition with the Navajo Supreme Court for review of these regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.

On May 18, 2005, APS, SRP, as the operating agent for the Navajo Plant, and the Navajo Nation executed a Voluntary Compliance Agreement to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

Supply

~~Water Supply~~

Assured supplies of water are important for APS’s generating plants. At the present time, APS has adequate water to meet its operating needs. 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.

Conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions, which, in addition to future supply conditions, have the potential to impact APS’s operations.

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San Juan River Adjudication. Both groundwater and surface water in areas important to APS’s operations have been the subject of inquiries, claims, and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss. In addition, APS is a party to a water contract that allows the company to secure water for Four Corners in the event of a water shortage 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. A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Arizona Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’s rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this adjudication. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Several of APS’s other power plants are also located within the geographic area subject to the summons, including a number of gas-fired power plants located within Maricopa and Pinal Counties. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Arizona Supreme Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’s water rights claims has been set in this matter.

At this time, the lower court proceedings in the Gila River adjudication are in the process of determining the specific hydro-geologic testing protocols for determining which groundwater wells located outside of the subflow zone of the Gila River should be subject to the adjudication court’s jurisdiction. A hearing to determine this jurisdictional test question was held in March 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. 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. A final decision by the trial court judge in this matter remains pending. Further proceedings have been initiated to determine the specific hydro-geologic testing protocols for subflow depletion determinations. The determinations made in this final stage of the proceedings may ultimately govern the adjudication of rights for parties, such as APS, that rely on groundwater extraction to support their industrial operations. APS cannot predict the outcome of these proceedings.

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Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. ~~Other claims~~No trial or pretrial proceedings have been ~~identified as ready for litigation in motions filed with the court. A trial is~~ scheduled for ~~June~~adjudication of ~~2020 regarding the contested~~APS’s water right claims. The adjudication court is currently conducting a trial of federal reserved water right claims ofasserted by the Hopi ~~tribe~~Tribe and by the United States as trustee for ~~federal reserve water rights. Similar claims of~~ the

~~Navajo Nation are pending, but~~ Tribe. In addition, the adjudication court has established a schedule for ~~discovery~~consideration of separate federal reserved water right claims asserted by the Navajo Nation and ~~resolution~~by the United States as trustee for the Nation. There is no established timeframe within which the adjudication court is expected to issue a final determination of ~~the tribe’s federal reserve~~ water rights ~~has not been established.~~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.

BUSINESS OF OTHER SUBSIDIARIES

Bright Canyon Energy

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. ~~BCE's focus~~BCE’s strategy is ~~on new growth opportunities~~to develop, own, operate and acquire energy infrastructure in a manner that ~~leverage~~leverages the Company’s core expertise in the electric energy industry. ~~BCE’s first initiative is~~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 ~~eleven~~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, ~~2019,~~2020, BCE had total assets of approximately ~~$14~~$27 million.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms ~~developed~~under development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, ~~(collectively, "Tenaska"),~~ the 242 MW Clear Creek wind farm in Missouri (“Clear Creek”) and the 250 MW Nobles 2 wind farm in ~~Minnesota. The~~Minnesota (“Nobles 2”). Clear Creek ~~project is expected to achieve~~achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under a long-term power purchase ~~agreement. The Nobles 2 project is also expected to achieve commercial operation in 2020 and deliver power under a long-term power purchase agreement.~~agreements. BCE indirectly owns 9.9% of ~~the~~ Clear Creek ~~project~~ and 5.1% of ~~the~~ Nobles ~~2 project.~~2.

El Dorado

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, ~~2019,~~2020, El Dorado had total assets of approximately $9$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.

~~4CA~~

~~4CA is a wholly-owned subsidiary~~Table of Pinnacle West. As of December 31, 2019, 4CA had total assets of approximately $55 million, primarily consisting of a note receivable from NTEC. See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generating Facilities - Coal-Fueled Generating Facilities - Four Corners" above for information regarding 4CA and the note receivable from NTEC.Contents

~~OTHER INFORMATION~~

~~Subpoenas~~

Pinnacle West previously received grand jury subpoenas issued in connection with an investigation by the office of the United States Attorney for the District of Arizona. The subpoenas sought information principally pertaining to the 2014 statewide election races in Arizona for Secretary of State and for positions on the ACC. The subpoenas requested records involving certain Pinnacle West officers and employees, including the Company’s former Chief Executive Officer, as well as communications between Pinnacle West personnel and a former ACC Commissioner. Pinnacle West understands the matter is closed.

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 Number of Employees at December 31, 2019		Principal Executive Office Address	Year of Incorporation	Approximate Number of Employees at December 31, 2020
Pinnacle West	400 North Fifth Street Phoenix, AZ 85004	1985	97	Pinnacle West	400 North Fifth Street Phoenix, AZ 85004	1985	88
APS	400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999	1920	6,111	APS	400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999	1920	5,933
BCE	400 East Van Buren Phoenix, AZ 85004	2014	2	BCE	400 East Van Buren Phoenix, AZ 85004	2014	5
El Dorado	400 East Van Buren Phoenix, AZ 85004	1983	—	El Dorado	400 East Van Buren Phoenix, AZ 85004	1983	—
4CA	400 North Fifth Street Phoenix, AZ 85004	2016	—	4CA	400 North Fifth Street Phoenix, AZ 85004	2016	—
Total			6,210	Total			6,026

Name

Age

Position

Period

Jeffrey B. Guldner

5455

Chairman of the Board, President and Chief Executive ~~Office~~Officer of Pinnacle West; Chairman of the Board and Chief Executive Officer of APS

2019-Present

President of APS

2018-2020

Executive Vice President, Public Policy of Pinnacle West

2017-2019

Executive Vice President, Public Policy of APS

2017-2018

General Counsel of Pinnacle West and APS

2017-2018

Senior Vice President, Public Policy of APS

2014-2017

~~Robert S. Bement~~

~~Executive Vice President and Special Advisor to the Chief Executive Officer of APS~~

~~2020-Present~~

~~Executive Vice President and Chief Nuclear Officer, PVGS, of APS~~

~~2016-2020~~

~~Senior Vice President, Site Operations, PVGS, of APS~~

~~2011-2016~~

Elizabeth A. Blankenship

4849

Vice President, Controller and Chief Accounting Officer of Pinnacle West and APS

2019-Present

General Manager, Accounting Operations of APS

2019-2019

Director, Accounting Operations of APS

2014-2019

Andrew D. Cooper

Vice President and Treasurer of Pinnacle West and APS

2020-Present

Director, Corporate Finance of Consolidated Edison Company of New York, Inc.

2017-2020

Director, Power & Utilities Investment Banking of Barclays Capital, Inc.

2008-2017

Donna M. Easterly

5556

Senior Vice President, Human Resources of APS

2020-Present

Vice President, Human Resources and Ethics of APS

2017-2020

Vice President, Chief Procurement Officer of APS

2014-2017

Daniel T. Froetscher

5859

President and Chief Operating Officer of APS

2020-Present

Executive Vice President, Operations of APS

2018-2020

Senior Vice President, Transmission, Distribution & Customers of APS

2014-2018

Theodore N. Geisler

4142

Senior Vice President and Chief Financial Officer of Pinnacle West and APS

2020-Present

Vice President and Chief Information Officer of APS

2018-2020

General Manager, Transmission and Distribution Operations and Maintenance of APS

2017-2018

Director, Investor Relations of Pinnacle West

2016-2017

Director, Transmission Operations and Maintenance of APS

2013-2016

James R. Hatfield

6263

Chief Administrative Officer ~~and Treasurer~~ of Pinnacle West and APS

2020-Present

Executive Vice President of Pinnacle West and APS

2012-Present

Treasurer of Pinnacle West and APS

2020-2020

Chief Financial Officer of Pinnacle West and APS

2008-2020

Maria L. Lacal

5960

Executive Vice President and Chief Nuclear Officer, PVGS, of APS

2020-Present

Senior Vice President, Regulatory and Oversight, PVGS, of APS

2016-2020

Vice President, Regulatory and Oversight, PVGS, of APS

2015-2016

Vice President, Operations Support, PVGS, of APS

2011-2015

Barbara D. Lockwood

5354

Senior Vice President, Public Policy of APS

2020-Present

Vice President, Regulation of APS

2015-2020

General Manager, Regulatory Policy and Compliance of APS

2014-2015

~~Lee R. Nickloy (a)~~

~~Vice President and Treasurer of Pinnacle West and APS~~

~~2010-Present~~

Robert E. Smith

5051

Senior Vice President and General Counsel of Pinnacle West and APS

2018-Present

Senior Vice President and General Counsel of Columbia Pipeline Group, Inc.

2014-2016

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~~(a) Lee R. Nickloy is retiring from Pinnacle West and APS on March 2, 2020.~~

PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange under stock symbol PNW. At the close of business on February ~~14, 2020,~~17, 2021, Pinnacle West’s common stock was held of record by approximately ~~16,942~~16,415 shareholders.

APS’s common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. The sole holder of APS’s common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. At December 31, ~~2019,~~2020, APS did not have any outstanding preferred stock.

Stock Performance Chart

~~ITEM 6. SELECTED FINANCIAL DATA~~

~~PINNACLE WEST CAPITAL CORPORATION – CONSOLIDATED~~

~~The selected data presented below as of and for~~This graph compares the cumulative total shareholder return on Pinnacle West’s common stock during the five years ended December 31, ~~2019, 2018, 2017, 2016~~2020 to the cumulative total returns on the S&P 500 Index and the Edison Electric Index. The comparison assumes that $100 was invested on December 31, 2015 ~~are derived from~~in Pinnacle West's common stock and in each of the ~~Consolidated Financial Statements. The data should be read in connection with~~indices shown and that all of the ~~Consolidated Financial Statements including the related notes included in Item 8 of this Form 10-K.~~dividends were reinvested.

Years Ended December 31,


Company/Index	2015	2016	2017	2018	2019	2020
Pinnacle West Common Stock	$100	$125	$141	$146	$159	$147
Edison Electric Institute Index	$100	$117	$131	$136	$171	$169
S&P 500 Index	$100	$112	$136	$130	$171	$203

2019 2018 2017 2016 2015
(dollars in thousands, except per share amounts)
OPERATING RESULTS

Operating revenues $ 3,471,209
$ 3,691,247
$ 3,565,296
$ 3,498,682
$ 3,495,443
Net income 557,813
530,540
507,949
461,527
456,190
Less: Net income attributable to noncontrolling interests 19,493
19,493
19,493
19,493
18,933
Net income attributable to common shareholders $ 538,320
$ 511,047
$ 488,456
$ 442,034
$ 437,257
COMMON STOCK DATA

Book value per share – year-end $ 48.30
$ 46.59
$ 44.80
$ 43.14
$ 41.30
Earnings per weighted-average common share outstanding:

Net income attributable to common shareholders – basic $ 4.79
$ 4.56
$ 4.37
$ 3.97
$ 3.94
Net income attributable to common shareholders – diluted $ 4.77
$ 4.54
$ 4.35
$ 3.95
$ 3.92
Dividends declared per share $ 3.04
$ 2.87
$ 2.70
$ 2.56
$ 2.44
Weighted-average common shares outstanding – basic 112,442,818
112,129,017
111,838,922
111,408,729
111,025,944
Weighted-average common shares outstanding – diluted 112,758,059
112,549,722
112,366,675
112,046,043
111,552,130
BALANCE SHEET DATA

Total assets $ 18,479,247
$ 17,664,202
$ 17,019,082
$ 16,004,253
$ 15,028,258
Liabilities and equity:

Current liabilities $ 2,078,365
$ 1,648,964
$ 1,197,852
$ 1,292,946
$ 1,442,317
Long-term debt less current maturities 4,832,558
4,638,232
4,789,713
4,021,785
3,462,391
Deferred credits and other 6,015,136
6,028,301
5,895,787
5,753,610
5,404,093
Total liabilities 12,926,059
12,315,497
11,883,352
11,068,341
10,308,801
Total equity 5,553,188
5,348,705
5,135,730
4,935,912
4,719,457
Total liabilities and equity $ 18,479,247
$ 17,664,202
$ 17,019,082
$ 16,004,253
$ 15,028,258

~~SELECTED FINANCIAL DATA~~

~~ARIZONA PUBLIC SERVICE COMPANY – CONSOLIDATED~~

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2019 2018 2017 2016 2015
(dollars in thousands)
OPERATING RESULTS

Operating revenues $ 3,471,209
$ 3,688,342
$ 3,557,652
$ 3,498,090
$ 3,494,900
Fuel and purchased power costs 1,042,237
1,094,020
992,744
1,082,625
1,101,298
Other operating expenses 1,741,988
1,764,554
1,640,369
1,556,980
1,556,670
Operating income 686,984
829,768
924,539
858,485
836,932
Other income 89,854
111,015
60,482
52,081
54,225
Interest expense — net of allowance for borrowed funds 201,646
206,211
192,051
183,090
176,109
Net income before income taxes 575,192
734,572
792,970
727,476
715,048
Income taxes (9,572 ) 144,814
269,168
245,842
245,841
Net income 584,764
589,758
523,802
481,634
469,207
Less: Net income attributable to noncontrolling interests 19,493
19,493
19,493
19,493
18,933
Net income attributable to common shareholder $ 565,271
$ 570,265
$ 504,309
$ 462,141
$ 450,274
BALANCE SHEET DATA

Total assets $ 18,370,723
$ 17,565,323
$ 16,893,751
$ 15,931,175
$ 14,982,182
Liabilities and equity:

Total equity $ 5,998,803
$ 5,786,797
$ 5,385,869
$ 5,037,970
$ 4,814,794
Long-term debt less current maturities 4,833,133
4,189,436
4,491,292
4,021,785
3,337,391
Total capitalization 10,831,936
9,976,233
9,877,161
9,059,755
8,152,185
Current liabilities 1,492,029
1,576,097
1,098,274
1,094,037
1,424,708
Deferred credits and other 6,046,758
6,012,993
5,918,316
5,777,383
5,405,289
Total liabilities and equity $ 18,370,723
$ 17,565,323
$ 16,893,751
$ 15,931,175
$ 14,982,182

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. This discussion provides a comparison of the ~~2019~~2020 results with ~~2018~~2019 results. A comparison of the ~~2018~~2019 results with ~~2017~~2018 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, ~~2018.~~2019. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.

OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about ~~$18~~$20 billion.For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS.APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.3 million retail customers in 11 of Arizona’s 15 counties.APS is also the operator and co-owner of Palo Verde -— a primary source of electricity for the southwest United States and the largest nuclear power plant in the United States.

COVID-19 Pandemic

The COVID-19 pandemic continues to be a rapidly evolving situation. It has led to economic disruption and volatility in financial markets worldwide. The Company is operating under long-standing pandemic and business continuity plans that exist to address situations including pandemics like COVID-19. We are focused on ensuring the health and safety of our employees, contractors and the general public by helping limit the spread of this virus and ensuring continued, safe and reliable electric service for APS customers.

We have identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue were to arise. Additionally, efforts to ensure the health and safety of our employees 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. 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 workplace. 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.

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Essential planned work and capital investments are continuing during the pandemic, with some non-essential planned work postponed to the first quarter of 2021. APS has continuous discussions with suppliers on manpower and supply issues pertaining to COVID-19 and has measures in place to continue to monitor resource needs and supply chain adequacy. At this time, APS does not believe it has any material supply chain risks due to COVID-19 that would impact its ability to serve customers’ needs.

The Company’s operations and maintenance expenses, exclusive of bad debt expense, increased by approximately $25 million for the year ended December 31, 2020 due to costs for personal protective equipment and other health and safety-related costs related to COVID-19. We expect the Company’s operation and maintenance expenses will continue to be impacted for 2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.

While the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13, 2020 through December 31, 2020, the cumulative impact in weather-normalized usage was approximately a 1% increase. During that period, APS’s retail electric residential weather-normalized sales increased 5%, and its retail electric commercial and industrial weather-normalized sales decreased 4% in the aggregate. APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat during 2021 as business activity continues to recover and more people return to work. Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

On March 31, 2020, a stay at home order became effective for the state of Arizona and remained in effect until May 16, 2020, when it was lifted and Arizona began reopening. In June 2020, Arizona saw an increase in the number of COVID-19 cases, hospitalizations, and deaths. Accordingly, on June 29, 2020, the governor of Arizona closed bars, indoor gyms and fitness clubs or centers, indoor movie theaters, water parks and tubing operations until July 27, 2020 as a partial reversal of the state’s reopening and to mitigate the spread of COVID-19. On July 23, 2020, the governor of Arizona extended these closures and they remained in place until August 27, 2020, when bars, gyms and movie theaters reopened with certain restrictions. We cannot predict the impact of the spread of COVID-19 in Arizona, whether there will be additional reclosures and how any such reclosures will impact our financial position, results of operations or cash flows. We are continuing to monitor the impacts of COVID-19.

As a result of the COVID-19 pandemic, in mid-March 2020, the commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020. In mid-April 2020, we were again able to utilize the commercial paper market and we have paid down the entire amount of the revolving credit facilities that were utilized as a result of the commercial paper market failure.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020 through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.

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On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020 through February 28, 2021. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020, but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements (see Note 1.)

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS waived all late payment fees during this suspension period. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. The Summer Disconnection Moratorium (see Note 4), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS also currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with this will result in a negative impact to its 2021 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. These estimated impact amounts for 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see Note 4).

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see Note 4). As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings.

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maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

More detailed discussion of the impacts and future uncertainties related to the COVID‑19 pandemic can be found throughout this Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Combined Notes to Pinnacle West’s and APS’s financial statements that appear in Part II, Item 8 of this report and “Risk Factors” in Part I, Item 1A of this report.

Strategic Overview

Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona by serving our customers with a clean, ~~affordable,~~ reliable and ~~customer-focused plan.~~

affordable energy.

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. Our vision for APS and Arizona presents an opportunity to engage with customers, communities, employees, policymakers, shareholders and others to achieve ~~clean energy goals. Guided by~~a shared, sustainable vision for Arizona.This goal is based on sound science ~~our approach is intended to encourage market-based~~ and ~~innovative solutions to drive towards a low-carbon economy. We believe clean energy can power a robust economy.~~supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

~~APS's~~APS’s new clean energy goals consist of three parts:

•~~An aspirational~~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; and

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

~~APS's~~APS’s ability to successfully execute its clean energy commitment is dependent upon a number of important external factors, some of which include a supportive regulatory environment, sales and customer growth, development of clean energy technologies and continued access to capital markets.

2050 ~~Aspirational~~ Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration.The 2050 goal will involve new thinking and depends on improved and new technologies.

2030 Goal: 65% Clean ~~Electricity.~~Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. ~~Those~~By building on those plans, ~~are intended to allow us~~APS intends to attain an energy mix that is 65% clean by 2030, with 45% of ~~APS's~~APS’s generation portfolio coming from renewable energy. Clean is measured as percent of energy mix which includes carbon-free resources like nuclear and demand-side management, and renewable is expressed as a percent of retail sales. This target will

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serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward 100% clean, carbon-free energy mix by 2050.

2031 Goal: End ~~APS's~~APS’s Use of Coal-Fired Generation. The commitment to end ~~APS's~~APS’s use of coal-fired generation by 2031 will require APS to cease ~~buying~~use of coal-generation ~~from~~at Four Corners.APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of ~~28%~~26% since 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.

APS understands that the transition away from coal-fired power plants toward a clean energy future will pose unique economic challenges for the communities around these plants. We worked collaboratively with stakeholders and leaders of the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired power plants on the communities surrounding those facilities to propose a comprehensive Coal Community Transition ("CCT") plan. The proposed framework provides substantial financial and economic development support to build new economic opportunities and addresses a transition strategy for plant employees. We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable projects. Our proposed CCT plan supports the Navajo Nation, where the Four Corners Power Plant is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant. The CCT plan is currently pending ACC approval. (See Note 4 for a discussion of the CCT plan.)

Renewables. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Its near-term actions include competitive solicitations to procure clean energy resources such as solar, wind, energy storage, demand response and DSM resources, ~~including energy efficiency resources that enable renewable additions and~~all of which lead to a cleaner ~~grid.~~grid.

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas.APS’s clean energy strategy includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS.Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio” in Item 1 for details regarding APS’s renewable energy resources.

Palo ~~Verde.~~Verde. Palo Verde, is the nation’s largest ~~producer~~carbon-free, clean energy resource, will continue to be a foundational part of ~~electricity and the largest source of carbon-free energy.~~APS’s resource portfolio. The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers. Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States. The plant’s continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.

Affordable

~~Affordable~~

We believe it is ~~APS's~~APS’s responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018 through December 2020, the average residential bill decreased by ~~7.8%~~7.3%, or ~~$11.68, due primarily to savings from lower operating costs in areas such as fuel and purchased power and federal tax reform that have been passed on to customers.~~$10.95.

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Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and ~~eliminating waste.~~internal efficiencies. Through the initiative and existing cost management practices, APS ~~identified~~met its goal of $20 million in ~~possible~~ cost savings ~~for~~as of December 31, 2020.

Participation in the EIM continues to be an effective tool for creating savings for ~~our~~APS's customers from the real-time, voluntary market. ~~Over~~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 ~~past three years, the EIM has delivered approximately $140 million in gross benefits to APS customers.~~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.

Reliable

~~Reliable~~

While our energy mix evolves, the obligation to deliver reliable service to our customers remains. ~~Excluding voluntary outages~~Notwithstanding the challenges presented by the COVID-19 pandemic as well as the hottest summer on record, APS continued to provide reliable service to its customers in 2020, setting a new all-time high peak energy demand of 7,660 MW, exceeding the prior peak set in 2017 by nearly 300 MW and ~~proactive fire mitigation efforts, APS finished 2019 with its best score for frequency of customer power outages.~~achieved strong reliability results.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data. ~~(See "Liquidity and Capital Resources - Capital Expenditures" below for additional details on capital expenditures.)~~

Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government entities and first responders and educate customers and communities. These programs contribute to customer reliability, responsible forest management and safe communities.

The new units at our modernized Ocotillo power plant provide cleaner-running and more efficient units. They support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening, when solar production declines as the sun sets and customer demand peaks.

Customer-Focused

~~Customer-Focused~~

Customers are at the core of what APS does every day and ~~APS is committed to providing options that make it easier for~~its focus remains on its customers and the communities it serves. It is APS’s goal to do business with them. In 2019, APS launched its redesigned aps.com website and mobile app, giving customers upgraded access to their energy usage data and billing information. APS's Customer Care team is using speech analytics to enrich advisors’ interactions with customers over the telephone, and customers can also communicate with APS throughachieve an ~~online chat.~~industry-leading best-in-class customer experience.

APS expanded financial help for its most vulnerable customers in 2019, allocating $2.75 million in crisis bill assistance and increasing the individual benefit for qualifying customers from $400 to $800 per year. The APS Solar Communities program has allowed more than 600 limited- and moderate-income customers to support clean energy and save money by hosting APS-owned solar systems on their residences in exchange for a monthly bill credit.

APS continues to develop and deploy innovative programs that connect customers with advanced technologies to help them manage their bills and encourage energy use during midday, when solar power is most abundant. Three energy storage programs incorporating smart thermostats, connected water heaters and batteries are helping customers shift energy use to times when they can take advantage of low-cost, abundant energy and reduce peak demand on APS's system.

In 2020, APS ~~is convening an~~adopted a number of changes to improve customer experience. It transitioned to a 24/7 care center operation to better serve its customers around the clock. APS improved its call center performance, answering nearly 75% of its more than 1.5 million telephone calls in 30 seconds or less. APS

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has also made many improvements to its digital experience through its aps.com site, and its overall digital experience continues to improve for its customers.

APS also convened a customer advisory ~~panel~~board and stakeholder committee in 2020 to serve as a vehicle for gathering valuable qualitative insights, directly from customers and stakeholders, that intends to keep APS apprised of ~~customers to gain a deeper understanding of~~customer needs, wants, and perspectives. Additionally, the customer ~~experience through their individual perspectives. A group of~~advisory board is leveraged to identify and diagnose potential customer ~~service advisors, in conjunction with local human services agencies, will provide in-person~~pain points and to help shape and co-create customer solutions.

APS is also providing assistance to residential and business customers that have been impacted by the COVID-19 pandemic. See “COVID-19 Pandemic” above for more information about customer support ~~in communities APS serves.~~during COVID-19.

Emerging Technologies

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 ~~this~~the agreement iswas scheduled to begin in ~~2021.~~2021; however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date. In 2018, APS issued ~~a request for proposal~~an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon ~~our~~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. ~~In February 2019, we contracted for the 141 MW and originally anticipated such~~These battery storage facilities ~~could~~are expected to be in service by ~~mid-2020.~~June 2022. Additionally, in February 2019, APS signed two 20-year 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. ~~The results of the~~APS has now completed its investigation will inform the timing of our utilization and implementation of batteries on our system. Due to the April 2019 event, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements is also dependent on the results of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and ~~requires~~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 ~~from the ACC~~in order to allow for cost recovery ~~of these agreements~~ 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 ~~150 MW of~~ energy storage projects under ~~power purchase agreements~~PPAs and AZ Sun retrofits described above. The ~~additional 700 MW of APS-owned~~remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the ~~retrofits associated with our~~market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites ~~as described above, along with current~~that were not included in the 2018 RFP referenced in the preceding paragraph; and ~~future RFPs for~~(ii) an ‘all source’ RFP that solicits both standalone energy storage and ~~solar~~renewable energy plus energy storage ~~projects. Given the April 2019 event, we continue~~resources. Such resources would be expected to ~~evaluate the appropriate timing~~be in service during 2023 and ~~path forward to support the overall capacity goals for our system and associated energy storage requirements. Currently,~~ 2024.

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Electric Vehicles

APS is ~~pursuing an RFP for battery-ready solar resources up to 150 MW with results expected in the first half of 2020.~~

~~Electric Vehicles~~

~~APS plans to make~~making electric vehicle charging more accessible for its customers and ~~help~~helping Arizona businesses, schools and governments electrify their fleets. In ~~2019,~~2020, APS ~~implemented~~expanded its Take Charge AZ Pilot ~~Program.~~Program and installed 84 dual-plug Level 2 charging stations at business customer locations with more stations expected to be added through 2021. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. ~~Rates are designed~~In addition to ~~encourage~~the Level 2 charging ~~overnight~~stations, APS will begin construction of direct current fast charging stations that will be owned and ~~during daytime off-peak hours when solar energy~~operated by APS at five locations in Arizona. This project is ~~abundant.~~

projected to be completed by the end of 2021 with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations. These stations will be accessible through the Electrify America charging network.

The ACC ordered the state’s public service corporations, including APS, to develop a long-term, comprehensive Statewide Transportation Electrification Plan (“TE Plan”) for Arizona. The TE Plan is intended to provide a roadmap for Transportation Electrification in Arizona, focused on realizing the associated air quality and economic development benefits for all residents in the state along with understanding the impact of electric vehicle charging on the grid. APS is actively participating in this process, which is scheduled to be completed by March 2021 and submitted to the ACC for review and approval.

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory and two other utilities, has been chosen by the ~~DOE's~~DOE’s Office of Nuclear Energy to participate in a hydrogen production project with the goal to improve the long-term economic competitiveness of the nuclear power industry. The multi-phase project is planned for 2020 through ~~2022,~~2023. In the first phase, Idaho National Laboratory will ~~look~~perform a technical and economic assessment of using electricity generated at ~~how hydrogen from~~ Palo Verde ~~may be used as energy storage for use in reverse-operable electrolysis or peaking gas turbines during times of the day when photovoltaic solar energy sources are~~to produce hydrogen.

~~unavailable and energy reserves in the southwest United States are low. It could also be used to support a rapidly increasing hydrogen transportation fuel market.~~

Experience from Palo Verde’s utility partners’ demonstration projects and from the ~~pilot project will~~Palo Verde-specific technical economic assessment is expected to offer insights into methods for flexible transitions between electricity and hydrogen generation ~~missions~~ in solar-dominated electricity ~~markets, and demonstrate how hydrogen may be used as energy storage to provide electricity during operating periods when solar is not available.~~

markets.

Carbon Capture

Carbon capture technologies can isolate ~~atmospheric~~ CO₂ and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. ~~At the same time, these generators are dispatchable: they can supply energy quickly as needed for reliability.~~ Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. ~~There are a number of demonstration projects that show promise but are still being tested in real-world conditions.~~ APS will continue to monitor this emerging technology.

Regulatory Overview

On October 31, 2019, APS filed an application with the ACC ~~for~~seeking an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual

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revenue increase in ~~APS's~~APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of ~~APS's~~APS’s application ~~are:~~were:

•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


		Capital Structure		Cost of Capital			Capital Structure		Cost of Capital
Long-term debt	Long-term debt	45.3	%	4.10	%	Long-term debt	45.3	%	4.1	%
Common stock equity	Common stock equity	54.7	%	10.15	%	Common stock equity	54.7	%	10.15	%
Weighted-average cost of capital	Weighted-average cost of capital			7.41	%	Weighted-average cost of capital			7.41	%

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•a Base Fuel Rate of $0.030168 per kWh;

•authorization to defer until ~~APS's~~APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•a number of proposed rate and program changes for residential customers, including:


▪	~~a super off-peak period during the winter months for APS’s time-of-use with demand rates;~~


▪	~~additional $1.25 million in funding for limited-income crisis bill program; and~~


▪	~~a flat bill/subscription rate pilot program;~~

▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and

▪a flat bill/subscription rate pilot program;

•proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and

•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).

APS requested that the increase become effective December 1, 2020.

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case.The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v)recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v)nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

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The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) the CCT plan related to the closure or future closure of coal-fired generation facilities of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers.

The hearing began January 14, 2021. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome of ~~its request.~~this proceeding.

See Note 4 for information regarding additional regulatory matters.

Arizona Attorney General Matter

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Financial Strength and Flexibility

Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital

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expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Other Subsidiaries

Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. ~~BCE's focus~~BCE’s strategy is ~~on new growth opportunities~~to develop, own, operate and acquire energy infrastructure in a manner that ~~leverage~~leverages the Company’s core expertise in the electric energy industry. ~~BCE’s first initiative is~~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 ~~eleven~~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.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms ~~developed~~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. The~~Minnesota (“Nobles 2”). Clear Creek ~~project is expected to achieve~~achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under a long-term power purchase ~~agreement. The Nobles 2 project is also expected to achieve commercial operation in 2020 and deliver power under a long-term power purchase agreement.~~agreements. BCE indirectly owns 9.9% of ~~the~~ Clear Creek ~~project~~ and 5.1% of ~~the~~ Nobles ~~2 project.~~2.

El Dorado. 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 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.

Key Financial Drivers

In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years ~~2017~~2018 through ~~2019,~~2020, retail electric revenues comprised approximately 95% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and

the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth.��Retail customers in APS’s service territory increased ~~2.0%~~2.3% for the year ended December 31, ~~2019~~2020 compared with the ~~prior year.~~prior-year period. For the three years ~~2017~~2018 through ~~2019,~~2020, APS’s customer growth averaged ~~1.8%~~2.0% per year. We currently project annual customer growth to be ~~1.5 -~~1.5% to 2.5% for ~~2020~~2021 and for ~~2020~~2021 through ~~2022~~2023 based on our assessment of steady ~~economic~~population growth in Arizona.

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Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased ~~0.6%~~1.4% for the year ended December 31, ~~2019~~2020 compared with the ~~prior year. Steady economic growth and~~prior-year period. While steady customer growth ~~were~~was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation ~~initiatives.~~ initiatives, the main drivers of positive sales for this period were continued strong residential sales due to work-from-home policies and a gradual improvement in sales to commercial and industrial customers. Though the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13, 2020 through December 31, 2020, the cumulative impact on weather-normalized usage was approximately a 1% increase. During that period, APS’s retail electric residential weather-normalized sales increased 5%, and its retail electric commercial and industrial weather-normalized sales decreased 4% in the aggregate. APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat into 2021 as business activity continues to recover and more people return to work.

For the three years ~~2017~~2018 through ~~2019,~~2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of ~~1.0 - 2.0%~~0.5% to 1.5% for ~~2020~~2021 and increase on average in the range of ~~1.0 -~~1.0% to 2.0% during ~~2020~~2021 through ~~2022,~~2023, including the effects of customer conservation, ~~and~~ energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather ~~variations and excluding the impacts~~variations. This projected sales growth range now includes our estimated contributions of several ~~new~~ large data centers, ~~opening operations in Metro Phoenix. The impact of new large data centers could raise the range of expected~~but not all, and we will continue to estimate contributions and evaluate sales ~~annual growth rate over the 2020 to 2022 period, but demand from~~guidance as these customers ~~remains uncertain at this point. Slower~~develop more usage history. These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, or acceleration of the expected effects of customer conservation, energy efficiency, or distributed renewable generation ~~initiatives could further~~initiatives.

Consistent with our focus on continuously looking for improvement in our processes and procedures, we updated our weather normalization methodology in 2020 to better leverage available AMI data (smart meter data). While the prior method only used one to two months of daily usage data to estimate weather impacts, the new method utilizes a rolling four-year period of daily usage data, which improves the accuracy of estimated weather impacts on energy sales since many more data points are used for each calculation.Our 1.4% weather normalized sales growth for the year ended December 31, 2020 reflects this change in methodology. The impact ~~these estimates.~~to our 2018-2020 average normalized sales growth from this change in methodology is 0.2%.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, ramp-up of data centers, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a ~~reasonable range of~~1% variation in our annual kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of ~~up to~~ approximately ~~$15~~$20 million.

Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historically, extreme weather variations have resulted in annual variations in net income in excess of $25 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.

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Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See ~~"Liquidity~~“Liquidity and Capital ~~Resources"~~Resources” below for information regarding the planned additions to our ~~facilities and income tax impacts related to bonus depreciation.~~facilities.

Pension and Other Postretirement Non-Service Credits, Net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was ~~10.9%~~10.8% of the assessed value for 2020, 10.9% for 2019 and 11.0% for ~~2018 and 11.2% for 2017.~~2018. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities.

Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Cuts and Jobs Act (the ~~"Tax Act"~~“Tax Act”) was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 5 for details of the impacts on the Company as of December 31, ~~2019.~~2020.) In ~~APS's~~APS’s 2017 Rate Case Decision, the ACC approved the TEAM, which is being used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)

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Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 7). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

RESULTS OF OPERATIONS

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost-based rate regulation) and related activities and includes electricity generation, transmission and distribution.

Operating Results – ~~2019~~2020 compared with ~~2018.~~

2019

Our consolidated net income attributable to common shareholders for the year ended December 31, ~~2019~~2020 was ~~$538~~$551 million, compared with ~~$511~~$538 million for the prior year. The results reflect an increase of approximately ~~$30~~$13 million for the regulated electricity segment primarily due to higher revenue driven by the effects of weather and lower ~~operations~~refunds in the current year related to the Tax Act, higher pension and ~~maintenance costs~~other postretirement non-service credits and ~~tax expense due to~~higher revenue from customer growth, partially offset by higher income taxes, including lower amortization of excess deferred taxes, ashigher depreciation and amortization expense, and higher other expenses. Weather had a significant impact on our result of ~~the Tax Act,~~

~~partially offset by lower revenue~~operations due to the ~~refunds provided~~hotter than normal weather in 2020 compared to ~~customers resulting from the Tax Act, and milder weather and lower pension and other postretirement non-service credits.~~2019.

The following table presents net income attributable to common shareholders by business segment compared with the prior year:


	Year Ended December 31,
	2020		2019		Net change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	2,589	$	2,425	$	164
Operations and maintenance	(953)		(939)		(14)
Depreciation and amortization	(614)		(591)		(23)
Taxes other than income taxes	(225)		(219)		(6)
Pension and other postretirement non-service credits — net	56		23		33
All other income and expenses, net	26		61		(35)
Interest charges, net of allowance for borrowed funds used during construction	(229)		(217)		(12)
Income taxes (Note 5)	(78)		16		(94)
Less income related to noncontrolling interests (Note 18)	(19)		(19)		—
Regulated electricity segment income	553		540		13
All other	(2)		(2)		—
Net Income Attributable to Common Shareholders	$	551	$	538	$	13

Year Ended
December 31,

2019 2018 Net change
(dollars in millions)
Regulated Electricity Segment:

Operating revenues less fuel and purchased power expenses $ 2,425
$ 2,590
$ (165 )
Operations and maintenance (939 ) (1,025 ) 86
Depreciation and amortization (591 ) (581 ) (10 )
Taxes other than income taxes (219 ) (212 ) (7 )
Pension and other postretirement non-service credits - net 23
50
(27 )
All other income and expenses, net 61
59
2
Interest charges, net of allowance for borrowed funds used during construction (217 ) (218 ) 1
Income taxes (Note 5) 16
(134 ) 150
Less income related to noncontrolling interests (Note 19) (19 ) (19 ) —
Regulated electricity segment income 540
510
30
All other (2 ) 1
(3 )
Net Income Attributable to Common Shareholders $ 538
$ 511
$ 27

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Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were ~~$165~~$164 million ~~lower~~higher for the year ended December 31, ~~2019~~2020 compared with the prior year. The following table summarizes the major components of this change:


	Increase (Decrease)
	Operating revenues		Fuel and purchased power expenses		Net change
	(dollars in millions)
Effects of weather	$	165	$	40	$	125
Lower refunds in the current year related to the Tax Act (Note 4)	85		—		85
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	(78)		(85)		7
Lost fixed cost recovery	7		—		7
Lower renewable energy regulatory surcharges, offset by operations and maintenance costs	(9)		—		(9)
Lower retail revenue due to the impacts of energy efficiency, distributed generation and changes in customer usage patterns, partially offset by higher customer growth	(4)		6		(10)
Lower transmission revenues (Note 4)	(17)		—		(17)
Arizona Attorney General Matter (Note 11)	(24)		—		(24)
Miscellaneous items, net	(10)		(10)		—
Total	$	115	$	(49)	$	164

Increase (Decrease)

Operating
revenues

Fuel and
purchased
power expenses
Net change
(dollars in millions)
Refunds due to lower Federal corporate income tax rate (Note 4) $ (146 ) $ —
$ (146 )
Effects of weather (32 ) (8 ) (24 )
Lower renewable energy regulatory surcharges and higher purchased power, offset by operations and maintenance costs (15 ) 2
(17 )
Change in residential rate design (a) 13
—
13
Lost fixed cost recovery 8
—
8
Higher retail revenue due to higher customer growth, partially offset by the impacts of energy efficiency, distributed generation and changes in customer usage patterns 10
5
5
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals (60 ) (61 ) 1
Miscellaneous items, net 5
10
(5 )
Total $ (217 ) $ (52 ) $ (165 )

(a) As part of the 2017 Settlement Agreement, rate design changes were implemented that moved some revenue responsibility from summer to non-summer months. The change was made to better align revenue collections with costs of service.

Operations and maintenance. Operations and maintenance expenses ~~decreased $86~~increased $14 million for the year ended December 31, ~~2019~~2020 compared with the prior-year period primarily because of:

~~A decrease~~•An increase of ~~$42~~$25 million primarily related to ~~public outreach~~COVID Customer Support Fund, personal protective equipment and other health and safety-related costs ~~at the parent company primarily associated with the ballot initiative in 2018;~~for COVID-19 response (see Note 4);

~~A decrease~~•An increase of ~~$28 million in fossil generation costs primarily due to lower planned outages and operating costs, including $4 million of Navajo Plant costs which were offset in depreciation and amortization;~~

~~A decrease of $19~~$22 million related to employee ~~benefit costs;~~benefits;

•An increase of $12 million related to customer bad debt expenses for the Summer Disconnection Moratorium and COVID-19 disconnect suspensions (see Note 4);

•An increase of $11 million for costs related to information technology;

•A decrease of ~~$18~~$21 million in nuclear generation costs primarily related to an increased recovery from contributions of administrative and general costs from Palo Verde owners;

•A decrease of $14 million related to consulting costs;

•A decrease of $13 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

~~An increase of $12 million for costs related to information technology;~~

~~An increase of $12 million related to consulting costs; and~~

•A decrease of $3$6 million for customer outreach costs; and

•A decrease of $2 million for corporate resources and other miscellaneous factors.

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Depreciation and amortization. Depreciation and amortization expenses were ~~$10~~$23 million higher for the year ended December 31, ~~2019~~2020 compared with the prior-year period primarily due to increased plant in service of ~~$33~~$37 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR ~~and Ocotillo modernization~~ project of ~~$19 million and the deferral of Navajo Plant costs of $4 million which is offset in operations and maintenance.~~$17 million.

Taxes other than income taxes. Taxes other than income taxes were $7$6 million higher for the year ended December 31, ~~2019~~2020 compared with the prior-year period primarily due to higher property values.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were ~~$27~~$33 million higher for the year ended December 31, 2020 compared to the prior-year period, primarily due to higher market returns in 2019.

All other income and expenses, net. All other income and expenses, net were $35 million lower for the year ended December 31, ~~2019~~2020 compared to the prior-year period primarily due to ~~lower market returns~~the current year CCT and APS Foundation contributions.

Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $12 million higher for the year ended December 31, 2020 compared to the prior-year period primarily due to higher debt balances in ~~2018.~~the current period.

Income taxes. Income taxes were ~~$150~~$94 million ~~lower~~higher for the year ended December 31, ~~2019~~2020 compared with the prior-year period primarily due to higher pre-tax net income and lower amortization of excess deferred taxes, ~~and lower pretax income in the current year period (see Note 5).~~partially offset by higher tax credits.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, ~~2019,~~2020, APS’s common equity ratio, as defined, was ~~52%~~51%. Its total shareholder equity was approximately ~~$5.9~~$6.2 billion, and total capitalization was approximately ~~$11.2~~$12.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately ~~$4.5~~$4.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West.

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Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities for the years ended December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in millions):

Pinnacle West Consolidated


	2019			2018				2020		2019
Net cash flow provided by operating activities	$	957		$	1,277		Net cash flow provided by operating activities	$	967	$	957
Net cash flow used for investing activities	(1,131		)	(1,193		)	Net cash flow used for investing activities	(1,278)		(1,131)
Net cash flow provided by (used for) financing activities	179			(92		)
Net increase (decrease) in cash and cash equivalents	$	5		$	(8	)
Net cash flow provided by financing activities							Net cash flow provided by financing activities	361		179
Net increase in cash and cash equivalents							Net increase in cash and cash equivalents	$	50	$	5

Arizona Public Service Company


	2020		2019
Net cash flow provided by operating activities	$	929	$	1,007
Net cash flow used for investing activities	(1,286)		(1,136)
Net cash flow provided by financing activities	404		133
Net increase in cash and cash equivalents	$	47	$	4

2019 2018
Net cash flow provided by operating activities $ 1,007
$ 1,255
Net cash flow used for investing activities (1,136 ) (1,187 )
Net cash flow provided by (used for) financing activities 133
(76 )
Net increase (decrease) in cash and cash equivalents $ 4
$ (8 )

Operating Cash Flows

~~2019~~2020 Compared with ~~2018.~~2019. Pinnacle West’s consolidated net cash provided by operating activities was $967 million in 2020 compared to $957 million in ~~2019 compared to $1,277 million in 2018.~~2019. The ~~decrease~~increase of ~~$320~~$10 million in net cash provided is primarily due to ~~lower~~higher cash receipts from electric revenues, ~~higher~~lower payments for operations and maintenance, lower pension contributions, lower customer advances for construction, lower income tax payments and lower other taxes, partially offset by higher fuel and purchased power ~~costs, property taxes, interest and higher pension contributions.~~costs. The difference between APS and Pinnacle ~~West's~~West’s net cash provided by operating activities primarily relates to ~~Pinnacle West's~~APS’s income tax cash payments to ~~APS, offset by lower operations and maintenance expense at the parent.~~Pinnacle West.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 ~~("ERISA"~~(“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was ~~117%~~124% funded as of January 1, ~~2020~~2021 and ~~112%~~117% as of January 1, ~~2019.~~2020. Under ~~GAAP,~~accounting principles generally accepted in the United States of America ("GAAP"), the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, ~~2020 and 90% funded as of January 1, 2019. See~~2020. (See Note 8 for additional ~~details.~~details). The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in 2018. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million ~~per year during the 2020-2022 period.~~in 2021 and zero thereafter. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in ~~2019~~2020 and ~~2018.~~2019. We do not expect to make

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any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior ~~years'~~years retiree medical claims from the other postretirement benefit plan trust assets.

Investing Cash Flows

~~2019~~2020 Compared with ~~2018.~~2019. Pinnacle West’s consolidated net cash used for investing activities was $1,278 million in 2020 compared to $1,131 million in ~~2019 compared to $1,193 million in 2018.~~2019. The ~~decrease~~increase of ~~$62~~$147 million in net cash used primarily related to ~~decreased~~increased capital expenditures and active union employee medical claim reimbursements (see Note 20). The difference between APS and Pinnacle West's net cash used for investing activities primarily relates to Pinnacle West's investing cash activity related to 4CA.expenditures.

Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)


	Estimated for the Year Ended December 31,
	2021		2022		2023
APS
Generation:
Clean:
Nuclear Generation	$	114	$	116	$	125

Renewables and Energy Storage Systems (“ESS”) (a)	200		276		281



Other Generation (b)	203		190		187
Distribution	577		556		549
Transmission	185		181		179
Other (c)	221		181		179
Total APS	$	1,500	$	1,500	$	1,500

Estimated for the Year Ended
December 31,
2020 2021 2022
APS

Generation:

Clean:
Nuclear Generation $ 131
$ 123
$ 123
Renewables and Energy Storage Systems ("ESS") (a) 121
490
671
Environmental 44
53
44
Other Generation 139
154
121
Distribution 554
444
446
Transmission 182
203
208
Other (b) 160
183
112
Total APS $ 1,331
$ 1,650
$ 1,725

(a)APS Solar Communities program, energy storage, renewable projects and other clean energy projects


~~(a)~~	~~APS Solar Communities program, energy storage, renewable projects and other clean energy projects~~


~~(b)~~	~~Primarily information systems and facilities projects~~

(b)Includes generation environmental projects

(c)Primarily information systems and facilities projects

Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and

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environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity

~~2019~~2020 Compared with ~~2018.~~2019. Pinnacle West’s consolidated net cash provided by financing activities was ~~$179~~$361 million in ~~2019~~2020 compared to ~~$92~~$179 million of net cash ~~used~~provided in ~~2018,~~2019, an increase of $182 million in net cash provided. The increase in net cash provided by financing activities includes $504 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $315 million, a net increase in short term borrowings of $16 million and higher dividend payments of $21 million.

APS’s consolidated net cash provided by financing activities was $404 million in 2020 compared to $133 million of net cash provided in 2019, an increase of $271 million in net cash provided. The increase in net cash provided by financing activities includes ~~$647~~lower long-term debt repayments of $135 million and $8 million in higher issuances of long-term debt, ~~partially offset by~~ higher ~~long-term debt repayments of $418 million, a net increase in short term borrowings of $57 million and higher dividend payments of $21 million.~~

APS’s consolidated net cash provided by financing activities was $133 million in 2019 compared to $76 million of net cash used in 2018, an increase of $209 million in net cash provided. The increase in net cash provided by financing activities includes $797 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $418 million, lower equity infusion of $150 million and higher dividend payments of ~~$20~~$21 million.

Significant Financing Activities. On December ~~18, 2019,~~16, 2020, the Pinnacle West Board of Directors declared a dividend of ~~$0.7825~~$0.83 per share of common stock, payable on March ~~2, 2020~~1, 2021 to shareholders of record on February ~~3, 2020.~~1, 2021. During ~~2019,~~2020, Pinnacle West increased its indicated annual dividend from ~~$2.95~~$3.13 per share to ~~$3.13~~$3.32 per share. For the year ended December 31, ~~2019,~~2020, Pinnacle ~~West's~~West’s total dividends paid per share of common stock were ~~$3.00~~$3.18 per share, which resulted in dividend payments of ~~$329~~$351 million.

On February 26, 2019, APS entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 0.50% per annum.

On ~~February~~ 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.

~~On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.~~

~~On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August 15, 2029.~~ ~~The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, and to replenish cash used to fund capital expenditures.~~

~~On November 20, 2019, APS issued~~ ~~$300 million~~ ~~of 3.5% unsecured~~ ~~senior notes that mature on December 1, 2049.~~ The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, to replenish cash used to fund capital expenditures, and to redeem, on December 30, 2019, ~~$100 million~~ ~~of the~~ ~~$250 million aggregate principal amount of~~ ~~our~~ ~~2.2%~~ ~~Notes due January 15, 2020.~~

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior ~~notes mentioned above.~~

notes.

On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and for general corporate purposes.

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On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

On November 19, 2020, APS reopened its $300 million, 2.6% unsecured senior notes that mature on August 15, 2029, and issued an additional $105 million of 2.6% unsecured senior notes. The aggregate balance of $405 million will mature on August 15, 2029. The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $49.4 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity

infusion. APS used this contribution to repay short-term indebtedness.

Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper.

On May ~~9, 2019,~~5, 2020, Pinnacle West ~~entered into~~refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a ~~$50~~new 364-day $31 million term loan agreement that matures May ~~7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility.~~4, 2021. Borrowings under the agreement bear interest at ~~LIBOR~~Eurodollar Rate plus ~~0.55%~~1.40% per annum. At December 31, ~~2019,~~2020, Pinnacle West had ~~$38~~$19 millionin outstanding borrowings under the agreement.

At December 31, ~~2019,~~2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle ~~West's~~West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle ~~West's~~West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, ~~2019,~~2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and ~~$77~~$150 million of commercial paper borrowings.

At December 31, ~~2019,~~2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, ~~2019,~~2020, APS had no ~~commercial paper outstanding and no~~ outstanding borrowings ~~or letters of credit~~ under its revolving credit ~~facilities.~~facilities, no letters of credit outstanding and no commercial paper borrowings. See ~~"Financial Assurances"~~“Financial Assurances” in Note 11 for a discussion of ~~APS's~~APS’s other outstanding letters of credit.

Other Financing Matters. See Note 1716 for information related to the change in our margin and collateral accounts.

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Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, ~~2019,~~2020, the ratio was approximately ~~52%~~54% for Pinnacle West and ~~47%~~49% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could ~~"cross-default"~~“cross-default” other debt. See further discussion of ~~"cross-default"~~“cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain ~~"rating triggers"~~“rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain ~~"cross-default"~~“cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain ~~"cross-default"~~“cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

See Note 7 for further discussions of liquidity matters.

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Credit Ratings

The ratings of securities of Pinnacle West and APS as of February ~~14, 2020~~23, 2021 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no

assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

Moody’s

Standard & Poor’s

Fitch

Pinnacle West

Corporate credit rating

A-

Senior unsecured

BBB+

A-

Commercial paper

P-2

A-2

Outlook

Negative

Stable

Negative

~~Moody’s~~

~~Standard & Poor’s~~

~~Fitch~~

~~Pinnacle West~~APS

Corporate credit rating

A3A2

A-

Senior unsecured

A3A2

~~BBB+~~A-

A-A

Commercial paper

~~P-2~~P-1

A-2

Outlook

Negative

Stable

Negative

~~APS~~

~~Corporate credit rating~~

A-

~~Senior unsecured~~

A-

~~Commercial paper~~

~~P-1~~

~~A-2~~

~~Outlook~~

~~Negative~~

~~Stable~~

~~Negative~~

Off-Balance Sheet Arrangements

See Note 1918 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

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Contractual Obligations

The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, ~~2019~~2020 (dollars in millions):


	2021		2022- 2023		2024- 2025		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	227	$	452	$	985	$	8,796	$	10,460
Pinnacle West	7		14		510		—		531
Total long-term debt payments, including interest	234		466		1,495		8,796		10,991
Short-term debt payments, including interest (b)	169		—		—		—		169
Fuel and purchased power commitments (c)	657		1,243		1,134		5,264		8,298
Renewable energy credits (d)	35		61		53		105		254
Purchase obligations (e)	115		60		22		185		382
Coal reclamation	16		35		39		69		159
Nuclear decommissioning funding requirements	2		4		4		48		58
Noncontrolling interests (f)	23		46		32		127		228
Operating lease payments (g)	14		20		11		37		82
Total contractual commitments	$	1,265	$	1,935	$	2,790	$	14,631	$	20,621

2020 2021-
2022 2023-
2024 Thereafter Total
Long-term debt payments, including interest: (a)

APS $ 554
$ 398
$ 757
$ 7,405
$ 9,114
Pinnacle West 460
—
—
—
460
Total long-term debt payments, including interest 1,014
398
757
7,405
9,574
Short-term debt payments, including interest (b) 115
—
—
—
115
Fuel and purchased power commitments (c) 569
1,217
1,176
5,318
8,280
Renewable energy credits (d) 36
66
58
133
293
Purchase obligations (e) 21
20
21
196
258
Coal reclamation 17
33
37
88
175
Nuclear decommissioning funding requirements 2
4
4
50
60
Noncontrolling interests (f) 23
46
39
143
251
Operating lease payments (g) 15
20
10
39
84
Total contractual commitments $ 1,812
$ 1,804
$ 2,102
$ 13,372
$ 19,090
(a)The long-term debt matures at various dates through 2050 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2020 (see Note 7).


~~(a)~~	The long-term debt matures at various dates through 2049 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2019 (see Note 7).

~~(b)~~

(b)See Note 6 for further details.

(c)Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).

(d)Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).

(e)These contractual obligations include commitments for capital expenditures and other obligations.

(f)Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 18).

(g)Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 9).


~~(c)~~	~~Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).~~


~~(d)~~	~~Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).~~


~~(e)~~	~~These contractual obligations include commitments for capital expenditures and other obligations.~~


~~(f)~~	~~Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 19).~~


~~(g)~~	~~Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 9).~~

This table excludes ~~$43~~$46 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. In January 2021, approximately $391 million of new fuel and purchased power commitments have been executed, primarily relating to periods after 2025 (see Note 9). Estimated minimum required pension contributions are zero for ~~2020,~~ 2021, 2022 and ~~2022~~2023 (see Note 8).

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those

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judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

Regulatory Accounting

Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings. Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities. We had ~~$1,507~~$1,426 million of regulatory assets and ~~$2,503~~$2,679 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, ~~2019.~~2020.

See Notes 1 and 4 for more information.

Pensions and Other Postretirement Benefit Accounting

Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit ~~liability~~assets, liabilities and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, ~~2019~~2020 reported pension assets and liability on the Consolidated Balance Sheets and our ~~2019~~2020 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

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	Increase (Decrease)							Increase (Decrease)
Actuarial Assumption (a)	Impact on Pension Liability			Impact on Pension Expense			Actuarial Assumption (a)	Impact on Pension Plans		Impact on Pension Expense
Discount rate:							Discount rate:
Increase 1%	$	(388	)	$	(11	)	Increase 1%	$	(429)	$	(12)
Decrease 1%	471			14			Decrease 1%	522		12
Expected long-term rate of return on plan assets:							Expected long-term rate of return on plan assets:
Increase 1%	—			(22		)	Increase 1%	—		(23)
Decrease 1%	—			22			Decrease 1%	—		23

Common Stock Treasury Stock Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount Shares Amount
Balance, December 31, 2016 111,392,053
$ 2,596,030
(55,317 ) $ (4,133 ) $ 2,255,547
$ (43,822 ) $ 132,290
$ 4,935,912

Net income —
—
488,456
—
19,493
507,949
Other comprehensive loss —
—
—
(1,180 ) —
(1,180 )
Dividends on common stock ($2.70 per share) —
—
(301,492 ) —
—
(301,492 )
Issuance of common stock 424,117
18,775
—
—
—
—
18,775
Purchase of treasury stock (a) —
(216,911 ) (17,755 ) —
—
—
(17,755 )
Reissuance of treasury stock for stock-based compensation and other —
207,765
16,264
—
—
—
16,264
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Balance, December 31, 2017 111,816,170
2,614,805
(64,463 ) (5,624 ) 2,442,511
(45,002 ) 129,040
5,135,730

Net income —
—
511,047
—
19,493
530,540
Other comprehensive income —
—
—
5,846
—
5,846
Dividends on common stock ($2.87 per share) —
—
(320,927 ) —
—
(320,927 )
Issuance of common stock 343,726
19,460
—
—
—
—
19,460
Purchase of treasury stock (a) —
(129,903 ) (10,338 ) —
—
—
(10,338 )
Reissuance of treasury stock for stock-based compensation and other —
136,231
11,137
—
—
—
11,137
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Reclassification of income tax effects related to new tax reform (b) —
—
8,552
(8,552 ) —
—
Balance, December 31, 2018 112,159,896
2,634,265
(58,135 ) (4,825 ) 2,641,183
(47,708 ) 125,790
5,348,705

Net income —
—
538,320
—
19,493
557,813
Other comprehensive loss —
—
—
(9,388 ) —
(9,388 )
Dividends on common stock ($3.04 per share) —
—
(341,893 ) —
—
(341,893 )
Issuance of common stock 380,230
25,296
—
—
—
—
25,296
Purchase of treasury stock (a) —
(121,493 ) (11,202 ) —
—
—
(11,202 )
Reissuance of treasury stock for stock-based compensation and other —
76,082
6,600
—
—
—
6,600
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Balance, December 31, 2019 112,540,126
$ 2,659,561
(103,546 ) $ (9,427 ) $ 2,837,610
$ (57,096 ) $ 122,540
$ 5,553,188

~~(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.~~

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Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)

84
Report of Independent Registered Public Accounting Firm			85
Pinnacle West Consolidated Statements of Income for 2020, 2019 and 2018			89
Pinnacle West Consolidated Statements of Comprehensive Income for 2020, 2019 and 2018			90
Pinnacle West Consolidated Balance Sheets as of December 31, 2020 and 2019			91
Pinnacle West Consolidated Statements of Cash Flows for 2020, 2019 and 2018			93
Pinnacle West Consolidated Statements of Changes in Equity for 2020, 2019 and 2018			94

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)			95
Report of Independent Registered Public Accounting Firm			96
APS Consolidated Statements of Income for 2020, 2019 and 2018			100
APS Consolidated Statements of Comprehensive Income for 2020, 2019 and 2018			101
APS Consolidated Balance Sheets as of December 31, 2020 and 2019			102
APS Consolidated Statements of Cash Flows for 2020, 2019 and 2018			104
APS Consolidated Statements of Changes in Equity for 2020, 2019 and 2018			105

~~(b)~~ Combined Notes to Consolidated Financial Statements			~~In 2018, the Company adopted new accounting guidance~~ 106



Note 1. Summary of Significant Accounting Policies			106
Note 2. Revenue			115
Note 3. New Accounting Standards			117
Note 4. Regulatory Matters			118
Note 5. Income Taxes			139
Note 6. Lines of Credit and ~~elected to reclassify income tax effects of the Tax Cuts~~Short-Term Borrowings			143
Note 7. Long-Term Debt and ~~Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.~~Liquidity Matters			144
Note 8. Retirement Plans and Other Postretirement Benefits			147
Note 9. Leases			156
Note 10. Jointly-Owned Facilities			159
Note 11. Commitments and Contingencies			160
Note 12. Asset Retirement Obligations			168
Note 13. Fair Value Measurements			169
Note 14. Earnings Per Share			175
Note 15. Stock-Based Compensation			175
Note 16. Derivative Accounting			178
Note 17. Other Income and Other Expense			182
Note 18. Palo Verde Sale Leaseback Variable Interest Entities			183
Note 19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds			183
Note 20. Changes in Accumulated Other Comprehensive Loss			187

~~The accompanying notes are an integral part~~

Table of ~~the financial statements.~~Contents

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(~~ARIZONA PUBLIC SERVICE COMPANY)~~PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for ~~Arizona Public Service Company.~~Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, ~~2019.~~2020. The effectiveness of our internal control over financial reporting as of December 31, ~~2019~~2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February ~~21, 2020~~24, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Arizona Public Service Company


	2020		2019
Net cash flow provided by operating activities	$	929	$	1,007
Net cash flow used for investing activities	(1,286)		(1,136)
Net cash flow provided by financing activities	404		133
Net increase in cash and cash equivalents	$	47	$	4

Operating Cash Flows

2020 Compared with 2019. Pinnacle West’s consolidated net cash provided by operating activities was $967 million in 2020 compared to $957 million in 2019. The increase of $10 million in net cash provided is primarily due to higher cash receipts from electric revenues, lower payments for operations and maintenance, lower pension contributions, lower customer advances for construction, lower income tax payments and lower other taxes, partially offset by higher fuel and purchased power costs. The difference between APS and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 124% funded as of January 1, 2021 and 117% as of January 1, 2020. Under accounting principles generally accepted in the United States of America ("GAAP"), the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, 2020. (See Note 8 for additional details). The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in 2018. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million in 2021 and zero thereafter. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019. We do not expect to make

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any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

Investing Cash Flows

2020 Compared with 2019. Pinnacle West’s consolidated net cash used for investing activities was $1,278 million in 2020 compared to $1,131 million in 2019. The increase of $147 million in net cash used primarily related to increased capital expenditures.

Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:

Capital Expenditures

(dollars in millions)


	Estimated for the Year Ended December 31,
	2021		2022		2023
APS
Generation:
Clean:
Nuclear Generation	$	114	$	116	$	125

Renewables and Energy Storage Systems (“ESS”) (a)	200		276		281



Other Generation (b)	203		190		187
Distribution	577		556		549
Transmission	185		181		179
Other (c)	221		181		179
Total APS	$	1,500	$	1,500	$	1,500

(a)APS Solar Communities program, energy storage, renewable projects and other clean energy projects

(b)Includes generation environmental projects

(c)Primarily information systems and facilities projects

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environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity

2020 Compared with 2019. Pinnacle West’s consolidated net cash provided by financing activities was $361 million in 2020 compared to $179 million of net cash provided in 2019, an increase of $182 million in net cash provided. The increase in net cash provided by financing activities includes $504 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $315 million, a net increase in short term borrowings of $16 million and higher dividend payments of $21 million.

APS’s consolidated net cash provided by financing activities was $404 million in 2020 compared to $133 million of net cash provided in 2019, an increase of $271 million in net cash provided. The increase in net cash provided by financing activities includes lower long-term debt repayments of $135 million and $8 million in higher issuances of long-term debt, higher equity infusion of $150 million and higher dividend payments of $21 million.

Significant Financing Activities. On December 16, 2020, the Pinnacle West Board of Directors declared a dividend of $0.83 per share of common stock, payable on March 1, 2021 to shareholders of record on February 1, 2021. During 2020, Pinnacle West increased its indicated annual dividend from $3.13 per share to $3.32 per share. For the year ended December 31, 2020, Pinnacle West’s total dividends paid per share of common stock were $3.18 per share, which resulted in dividend payments of $351 million.

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes.

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On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity

infusion. APS used this contribution to repay short-term indebtedness.

Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper.

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021. Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum. At December 31, 2020, Pinnacle West had $19 million in outstanding borrowings under the agreement.

At December 31, 2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $150 million of commercial paper borrowings.

At December 31, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding and no commercial paper borrowings. See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.

Other Financing Matters. See Note 16 for information related to the change in our margin and collateral accounts.

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Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2020, the ratio was approximately 54% for Pinnacle West and 49% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

See Note 7 for further discussions of liquidity matters.

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Credit Ratings

The ratings of securities of Pinnacle West and APS as of February 23, 2021 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

Moody’s

Standard & Poor’s

Fitch

Pinnacle West

Corporate credit rating

A-

Senior unsecured

BBB+

A-

Commercial paper

P-2

A-2

Outlook

Negative

Stable

Negative

APS

Corporate credit rating

A-

Senior unsecured

A-

Commercial paper

P-1

A-2

Outlook

Negative

Stable

Negative

Off-Balance Sheet Arrangements

See Note 18 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

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Contractual Obligations

The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2020 (dollars in millions):


	2021		2022- 2023		2024- 2025		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	227	$	452	$	985	$	8,796	$	10,460
Pinnacle West	7		14		510		—		531
Total long-term debt payments, including interest	234		466		1,495		8,796		10,991
Short-term debt payments, including interest (b)	169		—		—		—		169
Fuel and purchased power commitments (c)	657		1,243		1,134		5,264		8,298
Renewable energy credits (d)	35		61		53		105		254
Purchase obligations (e)	115		60		22		185		382
Coal reclamation	16		35		39		69		159
Nuclear decommissioning funding requirements	2		4		4		48		58
Noncontrolling interests (f)	23		46		32		127		228
Operating lease payments (g)	14		20		11		37		82
Total contractual commitments	$	1,265	$	1,935	$	2,790	$	14,631	$	20,621

(a)The long-term debt matures at various dates through 2050 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2020 (see Note 7).

(b)See Note 6 for further details.

(c)Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).

(d)Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).

(e)These contractual obligations include commitments for capital expenditures and other obligations.

(f)Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 18).

(g)Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 9).

This table excludes $46 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. In January 2021, approximately $391 million of new fuel and purchased power commitments have been executed, primarily relating to periods after 2025 (see Note 9). Estimated minimum required pension contributions are zero for 2021, 2022 and 2023 (see Note 8).

CRITICAL ACCOUNTING POLICIES

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Regulatory Accounting

Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings. Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities. We had $1,426 million of regulatory assets and $2,679 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2020.

See Notes 1 and 4 for more information.

Pensions and Other Postretirement Benefit Accounting

Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2020 reported pension assets and liability on the Consolidated Balance Sheets and our 2020 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

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	Increase (Decrease)
Actuarial Assumption (a)	Impact on Pension Plans		Impact on Pension Expense
Discount rate:
Increase 1%	$	(429)	$	(12)
Decrease 1%	522		12
Expected long-term rate of return on plan assets:
Increase 1%	—		(23)
Decrease 1%	—		23

(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2020 other postretirement benefit obligation and our 2020 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):


	Increase (Decrease)
Actuarial Assumption (a)	Impact on Other Postretirement Benefit Plans		Impact on Other Postretirement Benefit Expense
Discount rate:
Increase 1%	$	(77)	$	(1)
Decrease 1%	98		4
Healthcare cost trend rate (b):
Increase 1%	86		8
Decrease 1%	(70)		(4)
Expected long-term rate of return on plan assets – pretax:
Increase 1%	—		(5)
Decrease 1%	—		5

(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

(b)This assumes a 1% change in the initial and ultimate healthcare cost trend rate.

See Note 8 for further details about our pension and other postretirement benefit plans.

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Fair Value Measurements

We account for derivative instruments, investments held in our nuclear decommissioning trusts fund, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion of accounting policies and Note 13 for fair value measurement disclosures.

Asset Retirement Obligations

We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.

AROs as of December 31, 2020 are described further in Note 12.

OTHER ACCOUNTING MATTERS

On January 1, 2020, we adopted ASU 2016-13, and related amendments, pertaining to the measurement of credit losses on financial instruments. In 2020, we also adopted ASU 2018-14, related to defined benefit plan disclosures. (See Note 3 for additional information related to new accounting standards.)

MARKET AND CREDIT RISKS

Market Risks

Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust, other special use funds and benefit plan assets.

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Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Note 13 and Note 19), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2020 and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020 and 2019 (dollars in millions):

Pinnacle West – Consolidated


	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2020	Rates		Amount		Rates		Amount		Rates		Amount
2021	0.40	%	$	169	—		$	—	—		$	—
2022	—		—		—		—		—		—
2023	—		—		—		—		—		—
2024	—		—		—		—		3.35	%	250
2025	—		—		—		—		1.99	%	800
Years thereafter	—		—		0.18	%	36		3.95	%	5,280
Total			$	169			$	36			$	6,330
Fair value			$	169			$	36			$	7,577


	Short-Term Debt				Variable-Rate Long-Term Debt				Fixed-Rate Long-Term Debt
	Interest				Interest				Interest
2019	Rates		Amount		Rates		Amount		Rates		Amount
2020	2.06	%	$	115	2.16	%	$	350	2.23	%	$	450
2021	—		—		—		—		—		—
2022	—		—		—		—		—		—
2023	—		—		—		—		—		—
2024	—		—		—		—		3.78	%	365
Years thereafter	—		—		1.54	%	36		4.12	%	4,475
Total			$	115			$	386			$	5,290
Fair value			$	115			$	386			$	5,808

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The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2020 and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020 and 2019 (dollars in millions):

APS — Consolidated


	Variable-Rate Long-Term Debt			Fixed-Rate Long-Term Debt
		Interest				Interest
2020		Rates		Amount		Rates		Amount
2021		—		$	—	—		$	—
2022		—		—		—		—
2023		—		—		—		—
2024		—		—		3.35	%	250
2025		—		—		3.15	%	300
Years thereafter		0.18	%	36		3.95	%	5,280
Total				$	36			$	5,830
Fair value				$	36			$	7,068


	Variable-Rate Long-Term Debt			Fixed-Rate Long-Term Debt
		Interest				Interest
2019		Rates		Amount		Rates		Amount
2020		2.12	%	$	200	2.20	%	$	150
2021		—		—		—		—
2022		—		—		—		—
2023		—		—		—		—
2024		—		—		3.78	%	365
Years thereafter		1.54	%	36		4.12	%	4,475
Total				$	236			$	4,990
Fair value				$	236			$	5,508

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

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The following table shows the net pretax changes in mark-to-market of our derivative positions (dollars in millions):


	December 31, 2020		December 31, 2019
Mark-to-market of net positions at beginning of year	$	(71)	$	(58)
Decrease (Increase) in regulatory asset	57		(15)
Recognized in OCI:

Mark-to-market losses realized during the period	1		2
Change in valuation techniques	—		—
Mark-to-market of net positions at end of year	$	(13)	$	(71)

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2020 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. (See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.)


Source of Fair Value	2021		2022		2023		2024		2025		Total fair value
Observable prices provided by other external sources	$	(2)	$	(3)	$	(5)	$	(2)	$	—	$	(12)
Prices based on unobservable inputs	(1)		—		—		—		—		(1)
Total by maturity	$	(3)	$	(3)	$	(5)	$	(2)	$	—	$	(13)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets (dollars in millions):


	December 31, 2020 Gain (Loss)				December 31, 2019 Gain (Loss)
	Price Up 10%		Price Down 10%		Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity	$	4	$	(4)	$	—	$	—
Natural gas	49		(49)		55		(55)
Total	$	53	$	(53)	$	55	$	(55)

(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

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Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. (See Note 16 for a discussion of our credit valuation adjustment policy.)

ITEM 7A. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risks.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND

FINANCIAL STATEMENT SCHEDULES


			Page

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)			84
Report of Independent Registered Public Accounting Firm			85
Pinnacle West Consolidated Statements of Income for 2020, 2019 and 2018			89
Pinnacle West Consolidated Statements of Comprehensive Income for 2020, 2019 and 2018			90
Pinnacle West Consolidated Balance Sheets as of December 31, 2020 and 2019			91
Pinnacle West Consolidated Statements of Cash Flows for 2020, 2019 and 2018			93
Pinnacle West Consolidated Statements of Changes in Equity for 2020, 2019 and 2018			94

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)			95
Report of Independent Registered Public Accounting Firm			96
APS Consolidated Statements of Income for 2020, 2019 and 2018			100
APS Consolidated Statements of Comprehensive Income for 2020, 2019 and 2018			101
APS Consolidated Balance Sheets as of December 31, 2020 and 2019			102
APS Consolidated Statements of Cash Flows for 2020, 2019 and 2018			104
APS Consolidated Statements of Changes in Equity for 2020, 2019 and 2018			105

Combined Notes to Consolidated Financial Statements			106



Note 1. Summary of Significant Accounting Policies			106
Note 2. Revenue			115
Note 3. New Accounting Standards			117
Note 4. Regulatory Matters			118
Note 5. Income Taxes			139
Note 6. Lines of Credit and Short-Term Borrowings			143
Note 7. Long-Term Debt and Liquidity Matters			144
Note 8. Retirement Plans and Other Postretirement Benefits			147
Note 9. Leases			156
Note 10. Jointly-Owned Facilities			159
Note 11. Commitments and Contingencies			160
Note 12. Asset Retirement Obligations			168
Note 13. Fair Value Measurements			169
Note 14. Earnings Per Share			175
Note 15. Stock-Based Compensation			175
Note 16. Derivative Accounting			178
Note 17. Other Income and Other Expense			182
Note 18. Palo Verde Sale Leaseback Variable Interest Entities			183
Note 19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds			183
Note 20. Changes in Accumulated Other Comprehensive Loss			187

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MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(PINNACLE WEST CAPITAL CORPORATION)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2020. The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 24, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Pinnacle West Capital Corporation

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of ~~Arizona Public Service Company~~Pinnacle West Capital Corporation and subsidiaries (the ~~"Company"~~“Company”) as of December 31, ~~2019~~2020 and ~~2018,~~2019, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, ~~2019,~~2020, the related notes and the ~~schedule~~schedules listed in the Index at Item 15 (collectively referred to as the ~~"financial statements"~~“financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, ~~2019,~~2020, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, ~~2019~~2020 and ~~2018,~~2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2019,~~2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2019,~~2020, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based

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on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting — Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the Financial Statements.

Critical Audit Matter Description

Arizona Public Service Company (“APS”), which is a wholly-owned subsidiary of the Company, is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.

The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and

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return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.

We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

•We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

•We read management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019, and monitored activity by intervenors, the ACC and its staff and other testimony, as well as the Company’s rebuttal. The filing is still under review with the ACC. We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.

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•We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances.For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February ~~21, 2020~~24, 2021

We have served as the ~~Company's~~Company’s auditor since 1932.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(dollars and shares in thousands, except per share amounts)


	Year Ended December 31,
	2020		2019		2018

OPERATING REVENUES (NOTE 2)	$	3,586,982	$	3,471,209	$	3,691,247
OPERATING EXPENSES
Fuel and purchased power	993,419		1,042,237		1,076,116
Operations and maintenance	958,910		941,616		1,036,744
Depreciation and amortization	614,378		590,929		582,354
Taxes other than income taxes	224,835		218,579		212,849
Other expenses	7,288		5,888		9,497
Total	2,798,830		2,799,249		2,917,560
OPERATING INCOME	788,152		671,960		773,687
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	33,776		31,431		52,319
Pension and other postretirement non-service credits - net (Note 8)	56,341		22,989		49,791
Other income (Note 17)	56,703		50,263		24,896
Other expense (Note 17)	(57,776)		(17,880)		(17,966)
Total	89,044		86,803		109,040
INTEREST EXPENSE
Interest charges	247,501		235,251		243,465
Allowance for borrowed funds used during construction (Note 1)	(18,530)		(18,528)		(25,180)
Total	228,971		216,723		218,285
INCOME BEFORE INCOME TAXES	648,225		542,040		664,442
INCOME TAXES (Note 5)	78,173		(15,773)		133,902
NET INCOME	570,052		557,813		530,540
Less: Net income attributable to noncontrolling interests (Note 18)	19,493		19,493		19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	550,559	$	538,320	$	511,047

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC	112,666		112,443		112,129
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED	112,942		112,758		112,550

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic	$	4.89	$	4.79	$	4.56
Net income attributable to common shareholders — diluted	$	4.87	$	4.77	$	4.54

The accompanying notes are an integral part of the financial statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)


	Year Ended December 31,
	2020		2019		2018

NET INCOME	$	570,052	$	557,813	$	530,540

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $662, $0, and $(78)	(2,089)		0		(78)
Reclassification of net realized gain, net of tax expense of $171, $375, and $473 (Note 16)	592		1,137		1,527
Pension and other postretirement benefits activity, net of tax benefit (expense) of $1,371, $3,452, and $(1,585) (Note 8)	(4,203)		(10,525)		4,397
Total other comprehensive income (loss)	(5,700)		(9,388)		5,846

COMPREHENSIVE INCOME	564,352		548,425		536,386
Less: Comprehensive income attributable to noncontrolling interests	19,493		19,493		19,493

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	544,859	$	528,932	$	516,893

The accompanying notes are an integral part of the financial statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2020		2019
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	59,968	$	10,283
Customer and other receivables	313,576		266,426
Accrued unbilled revenues	132,197		128,165
Allowance for doubtful accounts	(19,782)		(8,171)
Materials and supplies (at average cost)	314,745		331,091
Fossil fuel (at average cost)	19,552		14,829

Income tax receivable (Note 5)	6,792		21,727
Assets from risk management activities (Note 16)	2,931		515
Deferred fuel and purchased power regulatory asset (Note 4)	175,835		70,137
Other regulatory assets (Note 4)	115,878		133,070
Other current assets	76,627		61,958
Total current assets	1,198,319		1,030,030
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 13 and 19)	1,138,435		1,010,775
Other special use funds (Notes 13 and 19)	254,509		245,095
Other assets	92,922		96,953
Total investments and other assets	1,485,866		1,352,823
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	20,837,885		19,836,292
Accumulated depreciation and amortization	(7,110,310)		(6,637,857)
Net	13,727,575		13,198,435
Construction work in progress	937,384		808,133
Palo Verde sale leaseback, net of accumulated depreciation of $253,014 and $249,144 (Note 18)	98,036		101,906
Intangible assets, net of accumulated amortization of $698,500 and $647,276	282,570		290,564
Nuclear fuel, net of accumulated amortization of $137,207 and $137,330	113,645		123,500
Total property, plant and equipment	15,159,210		14,522,538
DEFERRED DEBITS
Regulatory assets (Notes 1, 4 and 5)	1,133,987		1,304,073
Operating lease right-of-use assets (Note 9)	505,064		145,813
Assets for pension and other postretirement benefits (Note 8)	502,992		90,570
Other	34,983		33,400
Total deferred debits	2,177,026		1,573,856
TOTAL ASSETS	$	20,020,421	$	18,479,247

The accompanying notes are an integral part of the financial statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,
	2020		2019
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	318,585	$	346,448
Accrued taxes	159,551		144,899
Accrued interest	56,962		53,534
Common dividends payable	93,531		87,982
Short-term borrowings (Note 6)	169,000		114,675
Current maturities of long-term debt (Note 7)	0		800,000
Customer deposits	48,340		64,908
Liabilities from risk management activities (Note 16)	7,557		38,946
Liabilities for asset retirements (Note 12)	15,586		11,025

Operating lease liabilities (Note 9)	74,785		12,713
Regulatory liabilities (Note 4)	229,088		234,912
Other current liabilities	187,448		168,323
Total current liabilities	1,360,433		2,078,365
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7)	6,314,266		4,832,558
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	2,135,403		1,992,339
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,450,169		2,267,835
Liabilities for asset retirements (Note 12)	689,497		646,193
Liabilities for pension benefits (Note 8)	166,484		280,185
Liabilities from risk management activities (Note 16)	11,062		33,186
Customer advances	221,032		215,330
Coal mine reclamation	170,097		165,695
Deferred investment tax credit	191,372		196,468
Unrecognized tax benefits (Note 5)	5,834		6,189
Operating lease liabilities (Note 9)	361,336		51,872
Other	190,643		159,844
Total deferred credits and other	6,592,929		6,015,136
COMMITMENTS AND CONTINGENCIES (SEE NOTES)	0		0
EQUITY
Common stock, no par value; authorized 150,000,000 shares, 112,760,051 and 112,540,126 issued at respective dates	2,677,482		2,659,561
Treasury stock at cost; 72,006 shares at end of 2020 and 103,546 shares at end of 2019	(6,289)		(9,427)
Total common stock	2,671,193		2,650,134
Retained earnings	3,025,106		2,837,610
Accumulated other comprehensive loss (Note 20)	(62,796)		(57,096)
Total shareholders’ equity	5,633,503		5,430,648
Noncontrolling interests (Note 18)	119,290		122,540
Total equity	5,752,793		5,553,188
TOTAL LIABILITIES AND EQUITY	$	20,020,421	$	18,479,247

The accompanying notes are an integral part of the financial statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,
	2020		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	570,052	$	557,813	$	530,540
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	686,253		664,140		650,955
Deferred fuel and purchased power	(93,651)		(82,481)		(78,277)
Deferred fuel and purchased power amortization	(12,047)		49,508		116,750
Allowance for equity funds used during construction	(33,776)		(31,431)		(52,319)
Deferred income taxes	69,469		(1,479)		117,355
Deferred investment tax credit	(5,096)		(3,938)		(5,170)

Stock compensation	18,292		18,376		19,547
Changes in current assets and liabilities:
Customer and other receivables	(18,191)		(12,789)		37,530
Accrued unbilled revenues	(4,032)		9,005		(24,736)
Materials, supplies and fossil fuel	11,623		(51,826)		(6,103)
Income tax receivable	14,935		(21,727)		0
Other current assets	(30,640)		(3,507)		33,844
Accounts payable	(6,059)		50,641		(14,602)
Accrued taxes	14,652		(9,920)		6,597
Other current liabilities	22,520		(84,651)		28,174
Change in margin and collateral accounts — assets	404		(247)		143
Change in margin and collateral accounts — liabilities	100		(125)		(2,211)

Change in unrecognized tax benefits	2,220		2,704		(1,235)
Change in long-term regulatory liabilities	13,017		124,221		(109,284)
Change in other long-term assets	(67,453)		(82,895)		78,604
Change in other long-term liabilities	(186,227)		(132,666)		(48,958)
Net cash flow provided by operating activities	966,365		956,726		1,277,144
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,326,584)		(1,191,447)		(1,178,169)
Contributions in aid of construction	62,503		70,693		27,716
Allowance for borrowed funds used during construction	(18,530)		(18,528)		(25,180)
Proceeds from nuclear decommissioning trust sales and other special use funds	819,518		719,034		653,033
Investment in nuclear decommissioning trust and other special use funds	(822,608)		(722,181)		(672,165)
Other	7,883		11,452		1,941
Net cash flow used for investing activities	(1,277,818)		(1,130,977)		(1,192,824)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	1,596,672		1,092,188		445,245
Repayment of long-term debt	(915,150)		(600,000)		(182,000)
Short-term borrowings and (repayments) — net	73,325		54,275		(7,000)
Short-term debt borrowings under revolving credit facility	751,690		49,000		45,000
Short-term debt repayments under revolving credit facility	(770,690)		(65,000)		(57,000)
Dividends paid on common stock	(350,577)		(329,643)		(308,892)
Common stock equity issuance and purchases — net	(1,389)		692		(5,055)
Distributions to noncontrolling interests	(22,743)		(22,744)		(22,744)
Net cash flow provided by (used for) financing activities	361,138		178,768		(92,446)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	49,685		4,517		(8,126)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	10,283		5,766		13,892
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	59,968	$	10,283	$	5,766

The accompanying notes are an integral part of the financial statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands, except per share amounts)


	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount		Shares	Amount
Balance, December 31, 2017	111,816,170	$	2,614,805	(64,463)	$	(5,624)	$	2,442,511	$	(45,002)	$	129,040	$	5,135,730

Net income		—			—		511,047		—		19,493		530,540
Other comprehensive income		—			—		—		5,846		—		5,846
Dividends on common stock ($2.87 per share)		—			—		(320,927)		—		—		(320,927)
Issuance of common stock	343,726	19,460			—		—		—		—		19,460
Purchase of treasury stock (a)		—		(129,903)	(10,338)		—		—		—		(10,338)
Reissuance of treasury stock for stock-based compensation and other		—		136,231	11,137		—		—		—		11,137
Capital activities by noncontrolling interests		—			—		—		—		(22,743)		(22,743)
Reclassification of income tax effects related to new tax reform (b)		—			—		8,552		(8,552)		—		0
Balance, December 31, 2018	112,159,896	2,634,265		(58,135)	(4,825)		2,641,183		(47,708)		125,790		5,348,705

Net income		—			—		538,320		—		19,493		557,813
Other comprehensive loss		—			—		—		(9,388)		—		(9,388)
Dividends on common stock ($3.04 per share)		—			—		(341,893)		—		—		(341,893)
Issuance of common stock	380,230	25,296			—		—		—		—		25,296
Purchase of treasury stock (a)		—		(121,493)	(11,202)		—		—		—		(11,202)
Reissuance of treasury stock for stock-based compensation and other		—		76,082	6,600		—		—		—		6,600
Capital activities by noncontrolling interests		—			—		—		—		(22,743)		(22,743)
Balance, December 31, 2019	112,540,126	2,659,561		(103,546)	(9,427)		2,837,610		(57,096)		122,540		5,553,188

Net income		—			—		550,559		—		19,493		570,052
Other comprehensive loss		—			—		—		(5,700)		—		(5,700)
Dividends on common stock ($3.23 per share)		—			—		(363,063)		—		—		(363,063)
Issuance of common stock	219,925	17,921			—		—		—		—		17,921
Purchase of treasury stock (a)		—		(81,256)	(7,181)		—		—		—		(7,181)
Reissuance of treasury stock for stock-based compensation and other		—		112,796	10,319		—		—		—		10,319

Capital activities by noncontrolling interests		—			—		—		—		(22,743)		(22,743)
Balance, December 31, 2020	112,760,051	$	2,677,482	(72,006)	$	(6,289)	$	3,025,106	$	(62,796)	$	119,290	$	5,752,793

(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.

(b) In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings.

The accompanying notes are an integral part of the financial statements.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2020. The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 24, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and the Board of Directors of

Arizona Public Service Company

Phoenix, Arizona

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

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Definition and Limitations of Internal Control over Financial Reporting

Critical Audit Matter

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:

•We read relevant regulatory rate orders issued by the ACC for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.

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•We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.

/s/ Deloitte & Touche LLP

Phoenix, Arizona

February 24, 2021

We have served as the Company’s auditor since 1932.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)


	Year Ended December 31,										Year Ended December 31,
	2019			2018			2017				2020		2019		2018

OPERATING REVENUES (NOTE 2)	$	3,471,209		$	3,688,342		$	3,557,652		OPERATING REVENUES (NOTE 2)	$	3,586,982	$	3,471,209	$	3,688,342

OPERATING EXPENSES										OPERATING EXPENSES
Fuel and purchased power	1,042,237			1,094,020			992,744			Fuel and purchased power	993,419		1,042,237		1,094,020
Operations and maintenance	926,716			969,227			917,983			Operations and maintenance	945,181		926,716		969,227
Depreciation and amortization	590,844			580,694			532,423			Depreciation and amortization	614,293		590,844		580,694
Taxes other than income taxes	218,540			212,136			183,254			Taxes other than income taxes	224,790		218,540		212,136
Other expense	5,888			2,497			6,709			Other expense	7,288		5,888		2,497
Total	2,784,225			2,858,574			2,633,113			Total	2,784,971		2,784,225		2,858,574
OPERATING INCOME	686,984			829,768			924,539			OPERATING INCOME	802,011		686,984		829,768
OTHER INCOME (DEDUCTIONS)										OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction (Note 1)	31,431			52,319			47,011			Allowance for equity funds used during construction (Note 1)	33,776		31,431		52,319
Pension and other postretirement non-service credits - net (Note 8)	24,529			51,242			24,371			Pension and other postretirement non-service credits - net (Note 8)	57,359		24,529		51,242
Other income (Note 18)	46,884			22,746			3,013
Other expense (Note 18)	(12,990		)	(15,292		)	(13,913		)
Other income (Note 17)										Other income (Note 17)	51,755		46,884		22,746
Other expense (Note 17)										Other expense (Note 17)	(53,694)		(12,990)		(15,292)
Total	89,854			111,015			60,482			Total	89,196		89,854		111,015
INTEREST EXPENSE										INTEREST EXPENSE
Interest charges	220,174			231,391			214,163			Interest charges	233,452		220,174		231,391
Allowance for borrowed funds used during construction (Note 1)	(18,528		)	(25,180		)	(22,112		)	Allowance for borrowed funds used during construction (Note 1)	(18,530)		(18,528)		(25,180)
Total	201,646			206,211			192,051			Total	214,922		201,646		206,211
INCOME BEFORE INCOME TAXES	575,192			734,572			792,970			INCOME BEFORE INCOME TAXES	676,285		575,192		734,572
INCOME TAXES (Note 5)	(9,572		)	144,814			269,168			INCOME TAXES (Note 5)	88,764		(9,572)		144,814
NET INCOME	584,764			589,758			523,802			NET INCOME	587,521		584,764		589,758
Less: Net income attributable to noncontrolling interests (Note 19)	19,493			19,493			19,493
Less: Net income attributable to noncontrolling interests (Note 18)										Less: Net income attributable to noncontrolling interests (Note 18)	19,493		19,493		19,493
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	565,271		$	570,265		$	504,309		NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	568,028	$	565,271	$	570,265

The accompanying notes are an integral part of the financial statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)


	Year Ended December 31,										Year Ended December 31,
	2019			2018			2017				2020		2019		2018

NET INCOME	$	584,764		$	589,758		$	523,802		NET INCOME	$	587,521	$	584,764	$	589,758

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX										OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:										Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $0, ($78), and $24 (Note 17)	—			(78		)	(35		)
Reclassification of net realized loss, net of tax benefit of $375, $473, and $1,294 (Note 17)	1,137			1,527			2,225
Pension and other postretirement benefits activity, net of tax benefit (expense) of $3,136, ($1,159), and $977 (Note 8)	(9,552		)	3,465			(3,750		)
Net unrealized loss, net of tax benefit (expense) of $(18), $0, and $(78)										Net unrealized loss, net of tax benefit (expense) of $(18), $0, and $(78)	(18)		0		(78)
Reclassification of net realized gain, net of tax expense of $171, $375, and $473 (Note 16)										Reclassification of net realized gain, net of tax expense of $171, $375, and $473 (Note 16)	592		1,137		1,527
Pension and other postretirement benefits activity, net of tax benefit (expense) of $1,955, $3,136, and $(1,159) (Note 8)										Pension and other postretirement benefits activity, net of tax benefit (expense) of $1,955, $3,136, and $(1,159) (Note 8)	(5,970)		(9,552)		3,465
Total other comprehensive income (loss)	(8,415		)	4,914			(1,560		)	Total other comprehensive income (loss)	(5,396)		(8,415)		4,914

COMPREHENSIVE INCOME	576,349			594,672			522,242			COMPREHENSIVE INCOME	582,125		576,349		594,672
Less: Comprehensive income attributable to noncontrolling interests	19,493			19,493			19,493			Less: Comprehensive income attributable to noncontrolling interests	19,493		19,493		19,493

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	556,856		$	575,179		$	502,749		COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER	$	562,632	$	556,856	$	575,179

The accompanying notes are an integral part of the financial statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,							December 31,
	2019			2018				2020		2019
ASSETS							ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)							PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
Plant in service and held for future use	$	19,832,805		$	18,733,142		Plant in service and held for future use	$	20,834,424	$	19,832,805
Accumulated depreciation and amortization	(6,634,597		)	(6,362,771		)	Accumulated depreciation and amortization	(7,107,058)		(6,634,597)
Net	13,198,208			12,370,371			Net	13,727,366		13,198,208
Construction work in progress	808,133			1,170,062			Construction work in progress	937,384		808,133
Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19)	101,906			105,775
Intangible assets, net of accumulated amortization of $646,142 and $590,069	290,409			262,746
Nuclear fuel, net of accumulated amortization of $137,330 and $137,850	123,500			120,217
Palo Verde sale leaseback, net of accumulated depreciation of $253,014 and $249,144 (Note 18)							Palo Verde sale leaseback, net of accumulated depreciation of $253,014 and $249,144 (Note 18)	98,036		101,906
Intangible assets, net of accumulated amortization of $697,366 and $646,142							Intangible assets, net of accumulated amortization of $697,366 and $646,142	282,415		290,409
Nuclear fuel, net of accumulated amortization of $137,207 and $137,330							Nuclear fuel, net of accumulated amortization of $137,207 and $137,330	113,645		123,500
Total property, plant and equipment	14,522,156			14,029,171			Total property, plant and equipment	15,158,846		14,522,156
INVESTMENTS AND OTHER ASSETS							INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Notes 14 and 20)	1,010,775			851,134
Other special use funds (Notes 14 and 20)	245,095			236,101
Nuclear decommissioning trust (Notes 13 and 19)							Nuclear decommissioning trust (Notes 13 and 19)	1,138,435		1,010,775
Other special use funds (Notes 13 and 19)							Other special use funds (Notes 13 and 19)	254,509		245,095
Other assets	43,781			40,817			Other assets	46,010		43,781
Total investments and other assets	1,299,651			1,128,052			Total investments and other assets	1,438,954		1,299,651
CURRENT ASSETS							CURRENT ASSETS
Cash and cash equivalents	10,169			5,707			Cash and cash equivalents	57,310		10,169
Customer and other receivables	255,479			257,654			Customer and other receivables	312,644		255,479
Accrued unbilled revenues	128,165			137,170			Accrued unbilled revenues	132,197		128,165
Allowance for doubtful accounts	(8,171		)	(4,069		)	Allowance for doubtful accounts	(19,782)		(8,171)
Materials and supplies (at average cost)	331,091			269,065			Materials and supplies (at average cost)	314,745		331,091
Fossil fuel (at average cost)	14,829			25,029			Fossil fuel (at average cost)	19,552		14,829
Income tax receivable (Note 5)	7,313			—			Income tax receivable (Note 5)	0		7,313
Assets from risk management activities (Note 17)	515			1,113
Assets from risk management activities (Note 16)							Assets from risk management activities (Note 16)	2,931		515
Deferred fuel and purchased power regulatory asset (Note 4)	70,137			37,164			Deferred fuel and purchased power regulatory asset (Note 4)	175,835		70,137
Other regulatory assets (Note 4)	133,070			129,738			Other regulatory assets (Note 4)	115,878		133,070

Other current assets	38,895			35,111			Other current assets	47,593		38,895
Total current assets	981,492			893,682			Total current assets	1,158,903		981,492
DEFERRED DEBITS							DEFERRED DEBITS
Regulatory assets (Notes 1, 4, and 5)	1,304,073			1,342,941			Regulatory assets (Notes 1, 4, and 5)	1,133,987		1,304,073
Operating lease right-of-use assets (Note 9)	144,024			—			Operating lease right-of-use assets (Note 9)	503,475		144,024
Assets for other postretirement benefits (Note 8)	86,736			43,212
Assets for pension and other postretirement benefits (Note 8)							Assets for pension and other postretirement benefits (Note 8)	495,673		86,736
Other	32,591			128,265			Other	34,413		32,591
Total deferred debits	1,567,424			1,514,418			Total deferred debits	2,167,548		1,567,424
TOTAL ASSETS	$	18,370,723		$	17,565,323		TOTAL ASSETS	$	19,924,251	$	18,370,723

The accompanying notes are an integral part of the financial statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	December 31,							December 31,
	2019			2018				2020		2019
LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
CAPITALIZATION							CAPITALIZATION
Common stock	$	178,162		$	178,162		Common stock	$	178,162	$	178,162
Additional paid-in capital	2,721,696			2,721,696			Additional paid-in capital	2,871,696		2,721,696
Retained earnings	3,011,927			2,788,256			Retained earnings	3,216,955		3,011,927
Accumulated other comprehensive loss (Note 21)	(35,522		)	(27,107		)
Accumulated other comprehensive loss (Note 20)							Accumulated other comprehensive loss (Note 20)	(40,918)		(35,522)
Total shareholder equity	5,876,263			5,661,007			Total shareholder equity	6,225,895		5,876,263
Noncontrolling interests (Note 19)	122,540			125,790
Noncontrolling interests (Note 18)							Noncontrolling interests (Note 18)	119,290		122,540
Total equity	5,998,803			5,786,797			Total equity	6,345,185		5,998,803
Long-term debt less current maturities (Note 7)	4,833,133			4,189,436			Long-term debt less current maturities (Note 7)	5,817,945		4,833,133
Total capitalization	10,831,936			9,976,233			Total capitalization	12,163,130		10,831,936
CURRENT LIABILITIES							CURRENT LIABILITIES

Current maturities of long-term debt (Note 7)	350,000			500,000			Current maturities of long-term debt (Note 7)	0		350,000
Accounts payable	338,006			266,277			Accounts payable	311,699		338,006
Accrued taxes	136,328			176,357			Accrued taxes	148,970		136,328
Accrued interest	52,619			60,228			Accrued interest	56,322		52,619
Common dividends payable	88,000			82,700			Common dividends payable	93,500		88,000
Customer deposits	64,908			91,174			Customer deposits	48,340		64,908
Liabilities from risk management activities (Note 17)	38,946			35,506

Liabilities from risk management activities (Note 16)							Liabilities from risk management activities (Note 16)	7,557		38,946
Liabilities for asset retirements (Note 12)	11,025			19,842			Liabilities for asset retirements (Note 12)	15,586		11,025

Operating lease liabilities (Note 9)	12,549			—			Operating lease liabilities (Note 9)	74,695		12,549
Regulatory liabilities (Note 4)	234,912			165,876			Regulatory liabilities (Note 4)	229,088		234,912
Other current liabilities	164,736			178,137			Other current liabilities	190,420		164,736
Total current liabilities	1,492,029			1,576,097			Total current liabilities	1,176,177		1,492,029
DEFERRED CREDITS AND OTHER							DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 5)	2,033,096			1,812,664			Deferred income taxes (Note 5)	2,143,673		2,033,096
Regulatory liabilities (Notes 1, 4, 5 and 8)	2,267,835			2,325,976			Regulatory liabilities (Notes 1, 4, 5 and 8)	2,450,169		2,267,835
Liabilities for asset retirements (Note 12)	646,193			706,703			Liabilities for asset retirements (Note 12)	689,497		646,193
Liabilities for pension benefits (Note 8)	262,243			425,404			Liabilities for pension benefits (Note 8)	148,943		262,243
Liabilities from risk management activities (Note 17)	33,186			24,531
Liabilities from risk management activities (Note 16)							Liabilities from risk management activities (Note 16)	11,062		33,186
Customer advances	215,330			137,153			Customer advances	221,032		215,330
Coal mine reclamation	165,695			212,785			Coal mine reclamation	170,097		165,695
Deferred investment tax credit	196,468			200,405			Deferred investment tax credit	191,372		196,468
Unrecognized tax benefits (Note 5)	40,188			41,861			Unrecognized tax benefits (Note 5)	39,410		40,188
Operating lease liabilities (Note 9)	50,092			—			Operating lease liabilities (Note 9)	359,653		50,092
Other	136,432			125,511			Other	160,036		136,432
Total deferred credits and other	6,046,758			6,012,993			Total deferred credits and other	6,584,944		6,046,758
COMMITMENTS AND CONTINGENCIES (SEE NOTES)							COMMITMENTS AND CONTINGENCIES (SEE NOTES)	0		0
TOTAL LIABILITIES AND EQUITY	$	18,370,723		$	17,565,323		TOTAL LIABILITIES AND EQUITY	$	19,924,251	$	18,370,723

The accompanying notes are an integral part of the financial statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)


	Year Ended December 31,										Year Ended December 31,
	2019			2018			2017				2020		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES										CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	584,764		$	589,758		$	523,802		Net income	$	587,521	$	584,764	$	589,758
Adjustments to reconcile net income to net cash provided by operating activities:										Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel	664,055			649,295			608,935			Depreciation and amortization including nuclear fuel	686,168		664,055		649,295
Deferred fuel and purchased power	(82,481		)	(78,277		)	(48,405		)	Deferred fuel and purchased power	(93,651)		(82,481)		(78,277)
Deferred fuel and purchased power amortization	49,508			116,750			(14,767		)	Deferred fuel and purchased power amortization	(12,047)		49,508		116,750
Allowance for equity funds used during construction	(31,431		)	(52,319		)	(47,011		)	Allowance for equity funds used during construction	(33,776)		(31,431)		(52,319)
Deferred income taxes	48,367			59,927			249,465			Deferred income taxes	36,462		48,367		59,927
Deferred investment tax credit	(3,938		)	(5,170		)	(4,587		)	Deferred investment tax credit	(5,096)		(3,938)		(5,170)
Change in derivative instruments fair value	—			—			(373		)

Changes in current assets and liabilities:										Changes in current assets and liabilities:
Customer and other receivables	(12,075		)	35,406			(68,040		)	Customer and other receivables	(28,206)		(12,075)		35,406
Accrued unbilled revenues	9,005			(24,736		)	(4,485		)	Accrued unbilled revenues	(4,032)		9,005		(24,736)
Materials, supplies and fossil fuel	(51,826		)	(6,206		)	(6,503		)	Materials, supplies and fossil fuel	11,623		(51,826)		(6,206)
Income tax receivable	(7,313		)	—			11,174			Income tax receivable	7,313		(7,313)		0
Other current assets	(1,461		)	31,707			(6,775		)	Other current assets	(24,669)		(1,461)		31,707
Accounts payable	53,258			(15,608		)	(26,561		)	Accounts payable	(4,503)		53,258		(15,608)
Accrued taxes	(40,029		)	19,008			26,773			Accrued taxes	12,642		(40,029)		19,008
Other current liabilities	(82,138		)	25,070			27,912			Other current liabilities	29,587		(82,138)		25,070
Change in margin and collateral accounts — assets	(247		)	143			(300		)	Change in margin and collateral accounts — assets	404		(247)		143
Change in margin and collateral accounts — liabilities	(125		)	(2,211		)	(533		)	Change in margin and collateral accounts — liabilities	100		(125)		(2,211)

Change in unrecognized tax benefits	2,704			(1,235		)	5,891			Change in unrecognized tax benefits	2,220		2,704		(1,235)
Change in long-term regulatory liabilities	124,221			(109,284		)	45,764			Change in long-term regulatory liabilities	13,017		124,221		(109,284)
Change in other long-term assets	(85,725		)	77,952			(78,540		)	Change in other long-term assets	(65,139)		(85,725)		77,952
Change in other long-term liabilities	(129,682		)	(55,169		)	(31,106		)	Change in other long-term liabilities	(186,871)		(129,682)		(55,169)
Net cash flow provided by operating activities	1,007,411			1,254,801			1,161,730			Net cash flow provided by operating activities	929,067		1,007,411		1,254,801
CASH FLOWS FROM INVESTING ACTIVITIES										CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(1,191,447		)	(1,169,061		)	(1,381,930		)	Capital expenditures	(1,326,584)		(1,191,447)		(1,169,061)
Contributions in aid of construction	70,693			27,716			23,708			Contributions in aid of construction	62,503		70,693		27,716
Allowance for borrowed funds used during construction	(18,528		)	(25,180		)	(22,112		)	Allowance for borrowed funds used during construction	(18,530)		(18,528)		(25,180)
Proceeds from nuclear decommissioning trust sales and other special use funds	719,034			653,033			542,246			Proceeds from nuclear decommissioning trust sales and other special use funds	819,518		719,034		653,033
Investment in nuclear decommissioning trust and other special use funds	(722,181		)	(672,165		)	(544,527		)	Investment in nuclear decommissioning trust and other special use funds	(822,608)		(722,181)		(672,165)
Other	6,336			(1,789		)	(18,538		)	Other	(554)		6,336		(1,789)
Net cash flow used for investing activities	(1,136,093		)	(1,187,446		)	(1,401,153		)	Net cash flow used for investing activities	(1,286,255)		(1,136,093)		(1,187,446)
CASH FLOWS FROM FINANCING ACTIVITIES										CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	1,092,188			295,245			549,478			Issuance of long-term debt	1,099,722		1,092,188		295,245
Repayment of long-term debt	(600,000		)	(182,000		)	—			Repayment of long-term debt	(465,150)		(600,000)		(182,000)
Short-term borrowings and (repayments) — net	—			—			(135,500		)

Short-term debt borrowings under revolving credit facility	—			25,000			—			Short-term debt borrowings under revolving credit facility	540,000		0		25,000
Short-term debt repayments under revolving credit facility	—			(25,000		)	—			Short-term debt repayments under revolving credit facility	(540,000)		0		(25,000)
Dividends paid on common stock	(336,300		)	(316,000		)	(296,800		)	Dividends paid on common stock	(357,500)		(336,300)		(316,000)
Equity infusion from Pinnacle West	—			150,000			150,000			Equity infusion from Pinnacle West	150,000		0		150,000
Noncontrolling interests	(22,744		)	(22,744		)	(22,744		)	Noncontrolling interests	(22,743)		(22,744)		(22,744)
Net cash flow provided by (used for) financing activities	133,144			(75,499		)	244,434			Net cash flow provided by (used for) financing activities	404,329		133,144		(75,499)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,462			(8,144		)	5,011			NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	47,141		4,462		(8,144)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	5,707			13,851			8,840			CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	10,169		5,707		13,851
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	10,169		$	5,707		$	13,851		CASH AND CASH EQUIVALENTS AT END OF YEAR	$	57,310	$	10,169	$	5,707

The accompanying notes are an integral part of the financial statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(dollars in thousands)


	Common Stock			Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interests		Total
	Shares	Amount
Balance, December 31, 2017	71,264,947	$	178,162	$	2,571,696	$	2,533,954	$	(26,983)	$	129,040	$	5,385,869

Equity infusion from Pinnacle West		—		150,000		—		—		—		150,000
Net income		—		—		570,265		—		19,493		589,758
Other comprehensive income		—		—		—		4,914		—		4,914
Dividends on common stock		—		—		(321,001)		—		—		(321,001)

Reclassifications of income tax effects related to new tax reform (a)		—		—		5,038		(5,038)		—		0
Capital activities by noncontrolling interests		—		—		—		—		(22,743)		(22,743)
Balance, December 31, 2018	71,264,947	178,162		2,721,696		2,788,256		(27,107)		125,790		5,786,797


Net income		—		—		565,271		—		19,493		584,764
Other comprehensive loss		—		—		—		(8,415)		—		(8,415)
Dividends on common stock		—		—		(341,600)		—		—		(341,600)

Capital activities by noncontrolling interests		—		—		—		—		(22,743)		(22,743)
Balance, December 31, 2019	71,264,947	178,162		2,721,696		3,011,927		(35,522)		122,540		5,998,803

Equity infusion from Pinnacle West		—		150,000		—		—		—		150,000
Net income		—		—		568,028		—		19,493		587,521
Other comprehensive loss		—		—		—		(5,396)		—		(5,396)
Dividends on common stock		—		—		(363,000)		—		—		(363,000)


Capital activities by noncontrolling interests		—		—		—		—		(22,743)		(22,743)
Balance, December 31, 2020	71,264,947	$	178,162	$	2,871,696	$	3,216,955	$	(40,918)	$	119,290	$	6,345,185

Common Stock Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Noncontrolling Interests Total
Shares Amount
Balance, December 31, 2016 71,264,947
$ 178,162
$ 2,421,696
$ 2,331,245
$ (25,423 ) $ 132,290
$ 5,037,970

Equity infusion from Pinnacle West —
150,000
—
—
—
150,000
Net income —
—
504,309
—
19,493
523,802
Other comprehensive loss —
—
—
(1,560 ) —
(1,560 )
Dividends on common stock —
—
(301,600 ) —
—
(301,600 )
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Balance, December 31, 2017 71,264,947
178,162
2,571,696
2,533,954
(26,983 ) 129,040
5,385,869

Equity infusion from Pinnacle West —
150,000
—
—
—
150,000
Net income —
—
570,265
—
19,493
589,758
Other comprehensive income —
—
—
4,914
—
4,914
Dividends on common stock —
—
(321,001 ) —
—
(321,001 )
Reclassifications of income tax effects related to new tax reform (a) —
—
5,038
(5,038 ) —
—
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Balance, December 31, 2018 71,264,947
178,162
2,721,696
2,788,256
(27,107 ) 125,790
5,786,797

Net income —
—
565,271
—
19,493
584,764
Other comprehensive loss —
—
—
(8,415 ) —
(8,415 )
Dividends on common stock —
—
(341,600 ) —
—
(341,600 )
Capital activities by noncontrolling interests —
—
—
—
(22,743 ) (22,743 )
Balance, December 31, 2019 71,264,947
$ 178,162
$ 2,721,696
$ 3,011,927
$ (35,522 ) $ 122,540
$ 5,998,803

(a)In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on

items within accumulated other comprehensive income to retained earnings.

The accompanying notes are an integral part of the financial statements.

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1. Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all 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. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the ~~Company's~~Company’s core expertise in the electric energy industry. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El ~~Paso's~~Paso’s 7% interest in Four Corners. ~~See~~(See Note 11 for more information on 4CA matters.)

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. ~~See~~(See Note 1918 for additional information.)

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ~~("GAAP"~~(“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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Regulatory Accounting

APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.

Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.

See Note 4 for additional information.

Electric Revenues

~~On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers; accordingly our 2019 and 2018 electric revenues~~Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a ~~"book-out"~~“book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

See Notes 2 and 4 for additional information.

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Allowance for Doubtful Accounts

The allowance for doubtful accounts represents our best estimate of ~~existing~~ accounts receivable and accrued unbilled revenues that will ultimately be ~~uncollectible.~~uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to ~~utility~~retail electric revenues. The write-off ~~factors~~factor used to estimate uncollectible accounts ~~are~~is based upon consideration of ~~both~~ historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections ~~success given the existing collections environment.~~success. (See Note 2.)

Property, Plant and Equipment

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

•material and labor;

•contractor costs;

•capitalized leases;

•construction overhead costs (where applicable); and

•allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, ~~2019~~2020 and ~~2018~~2019 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment: 2019 2018
Generation $ 8,916,872
$ 8,285,514
Transmission 3,095,907
3,033,579
Distribution 6,690,697
6,378,345
General plant 1,132,816
1,039,190
Plant in service and held for future use 19,836,292
18,736,628
Accumulated depreciation and amortization (6,637,857 ) (6,366,014 )
Net 13,198,435
12,370,614
Construction work in progress 808,133
1,170,062
Palo Verde sale leaseback, net of accumulated depreciation 101,906
105,775
Intangible assets, net of accumulated amortization 290,564
262,902
Nuclear fuel, net of accumulated amortization 123,500
120,217
Total property, plant and equipment $ 14,522,538
$ 14,029,570


Property, Plant and Equipment:	2020		2019
Generation	$	9,199,012	$	8,916,872
Transmission	3,290,477		3,095,907
Distribution	7,107,007		6,690,697
General plant	1,241,389		1,132,816
Plant in service and held for future use	20,837,885		19,836,292
Accumulated depreciation and amortization	(7,110,310)		(6,637,857)
Net	13,727,575		13,198,435
Construction work in progress	937,384		808,133
Palo Verde sale leaseback, net of accumulated depreciation	98,036		101,906
Intangible assets, net of accumulated amortization	282,570		290,564
Nuclear fuel, net of accumulated amortization	113,645		123,500
Total property, plant and equipment	$	15,159,210	$	14,522,538

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. ~~See~~(See Note 12 for additional information.)

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APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, ~~2019~~2020 were as follows:

•Fossil plant — 17 years;

•Nuclear plant — 2220 years;

•Other generation — 2120 years;

•Transmission — 4038 years;

•Distribution — 34 years; and

•General plant — 87 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $553 million in 2020, $522 million in 2019, and $486 million in ~~2018, and $453 million in 2017.~~2018. For the years ~~2017~~2018 through ~~2019,~~2020, the depreciation rates ranged from a low of 0.18% to a high of ~~24.49%~~32.43%. The weighted-average depreciation rate was 2.84% in 2020, 2.81% in 2019, and 2.81% in ~~2018, and 2.80% in 2017.~~2018.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 12 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

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AFUDC was calculated by using a composite rate of 6.72% for 2020, 6.98% for 2019, and 7.03% for ~~2018, and 6.68% for 2017.~~2018. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020 but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Materials and Supplies

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost. ~~See~~(See Note 7 for additional information.)

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

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The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.

See Note 1413 for additional information about fair value measurements.

Derivative Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and ~~fuels.~~natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. ~~See~~(See Note 1716 for additional information about our derivative instruments.)

Loss Contingencies and Environmental Liabilities

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its ~~subsidiaries.~~subsidiaries, in addition to a non-qualified pension plan. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. ~~See~~(See Note 8 for additional information on pension and other postretirement benefits.)

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Nuclear Fuel

APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of ~~2019. See~~2022. (See Note 11 for information on spent nuclear fuel disposal costs.)

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. ~~See~~(See Note 5 for additional discussion.)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Cash and Cash Equivalents

We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):


	Year ended December 31,
	2020		2019		2018
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(3,019)	$	12,535	$	21,173
Interest, net of amounts capitalized	216,951		218,664		208,479
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	113,502	$	141,297	$	132,620
Dividends declared but not paid	93,531		87,982		82,675

Sale of 4CA 7% interest in Four Corners	0		0		68,907

112

Year ended December 31,
2019 2018 2017
Cash paid during the period for:

Income taxes, net of refunds $ 12,535
$ 21,173
$ 2,186
Interest, net of amounts capitalized 218,664
208,479
189,288
Significant non-cash investing and financing activities:

Accrued capital expenditures $ 141,297
$ 132,620
$ 130,404
Dividends declared but not paid 87,982
82,675
77,667
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262
—
—
Sale of 4CA 7% interest in Four Corners —
68,907
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):


	Year ended December 31,
	2020		2019		2018
Cash paid (received) during the period for:
Income taxes, net of refunds	$	41,176	$	(15,042)	$	77,942
Interest, net of amounts capitalized	206,328		204,261		196,419
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	113,502	$	141,297	$	132,620
Dividends declared but not paid	93,500		88,000		82,700

Year ended December 31,
2019 2018 2017
Cash paid (received) during the period for:

Income taxes, net of refunds $ (15,042 ) $ 77,942
$ (14,098 )
Interest, net of amounts capitalized 204,261
196,419
184,210
Significant non-cash investing and financing activities:

Accrued capital expenditures $ 141,297
$ 132,620
$ 130,057
Dividends declared but not paid 88,000
82,700
77,700
Right-of-use operating lease assets obtained in exchange for operating lease liabilities 11,262
—
—

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily ~~APS's~~APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $70 million in 2020, $66 million in 2019, and $68 million in ~~2018, and $72 million in 2017.~~2018. Estimated amortization expense on existing intangible assets over the next five years is $68 million in ~~2020, $52 million in~~ 2021, ~~$41~~$56 million in 2022, ~~$32~~$48 million in 2023, ~~and $22~~$33 million in ~~2024.~~2024, and $25 million in 2025. At December 31, ~~2019,~~2020, the weighted-average remaining amortization period for intangible assets was 87 years.

Investments

El Dorado holds investments in both debt and equity securities. Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

Our investments in the nuclear decommissioning trusts, coal reclamation escrow ~~account~~accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. ~~See~~(See Notes 1413 and 2019 for more information on these investments.)

Leases

We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value

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of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.

APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). We also may enter into lease agreements related to vehicles, office space, land, and other equipment. (See Note 9 for information on our lease agreements.)

Business Segments

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, ~~2019,~~2020, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

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2. Revenue

Sources of Revenue

The following table provides detail of Pinnacle ~~West's~~West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):


	Year Ended December 31,			Year Ended December 31,		Year Ended December 31,
	2020			2019		2018
Retail Electric Service
Residential	$	1,929,178	(a)	$	1,761,122	$	1,867,370
Non-Residential	1,486,098			1,509,514		1,628,891
Wholesale Energy Sales	93,345			121,805		109,198
Transmission Services for Others	65,859			62,460		60,261
Other Sources	12,502			16,308		25,527
Total Operating Revenues	$	3,586,982		$	3,471,209	$	3,691,247

Year Ended December 31, Year Ended December 31,
2019 2018
Retail Electric Service
Residential $ 1,761,122
$ 1,867,370
Non-Residential 1,509,514
1,628,891
Wholesale Energy Sales 121,805
109,198
Transmission Services for Others 62,460
60,261
Other Sources 16,308
25,527
Total Operating Revenues $ 3,471,209
$ 3,691,247

(a) Residential revenues for the year ended December 31, 2020 reflect a $24 million reduction related to the Arizona Attorney General matter. (See Note 11).

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Retail Electric Revenue. Pinnacle ~~West's~~West’s retail electric revenue is generated by our wholly owned regulated subsidiary ~~APS's~~APS’s sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain ~~customers'~~customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail ~~customers'~~customers’ energy requirements. We may also sell ~~generation~~ into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2020, 2019 and 2018 were $3,533 million, $3,415 million and $3,644 million, respectively.

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We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the year ended December 31, 2020, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $54 million, $56 million and $47 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. ~~See~~(See Note 4 for a discussion of our regulatory cost recovery mechanisms.)

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, ~~2019~~2020 and ~~2018.~~2019.

Allowance for Doubtful Accounts

On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. Our disconnection policies are also impacted by the Summer Disconnection Moratorium.The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. (See Note 1 for our accounting policies on allowance for doubtful accounts. See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.)

The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts all of which primarily relates to APS (dollars in thousands):


	Year Ended December 31, 2020		Year Ended December 31, 2019		Year Ended December 31, 2018
Allowance for doubtful accounts, balance at beginning of period	$	8,171	$	4,069	$	2,513
Bad debt expense	20,633		11,819		10,870
Actual write-offs	(9,022)		(7,717)		(9,314)
Allowance for doubtful accounts, balance at end of period	$	19,782	$	8,171	$	4,069

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3. New Accounting Standards

Standards Adopted in ~~2019~~

~~ASU 2016-02, Leases~~

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 9 for additional information.

~~ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract~~

In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard was effective for us on January 1, 2020, with early application permitted, and may have been applied using either a retrospective or prospective transition approach. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

~~Standard Adopted in~~ 2020

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. (See Note 2 for allowance for doubtful accounts related credit loss disclosures.)

ASU 2018-14, Retirement Benefits: Changes to the Disclosure Requirements for Defined Benefit Plans

In August 2018, a new accounting standard was issued that amends certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that are no longer considered beneficial, clarifies specific disclosure requirements and adds new disclosure requirements relating to defined benefit plans. The new standard is effective for fiscal years ending after December 15, 2020. We adopted and implemented the standard on a retrospective basis in our financial statements for the year ended December 31, 2020. While the adoption of this guidance modified the disclosure requirements relating to defined benefit plans, these changes did not have a material impact on our financial statements. (See Note 8 for Retirement Plans and Other Postretirement Benefits disclosure.)

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4. Regulatory Matters

COVID-19 Pandemic

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS waived all late payment fees during this suspension period. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. The Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see below for discussion of EIS, TEAM Phase II and PSA).

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).

APS has spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS

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has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.

2019 Retail Rate Case Filing with the Arizona Corporation Commission

~~On October 31,~~In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC ~~for~~on October 31, 2019 seeking an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ~~("SCR"~~(“SCR”) project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual revenue increase in ~~APS's~~APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of ~~APS's~~APS’s application ~~are:~~were:

•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•the following proposed capital structure and costs of capital:


	Capital Structure		Cost of Capital
Long-term debt	45.3	%	4.10	%
Common stock equity	54.7	%	10.15	%
Weighted-average cost of capital			7.41	%

•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);

•a number of proposed rate and program changes for residential customers, including:


▪	~~a super off-peak period during the winter months for APS’s time-of-use with demand rates;~~


▪	~~additional $1.25 million in funding for APS's limited-income crisis bill program; and~~


▪	~~a flat bill/subscription rate pilot program;~~

▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and

▪a flat bill/subscription rate pilot program;

•proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and

•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see ~~"Navajo Plant"~~“Navajo Plant” below).

APS requested that the increase become effective December 1, 2020.

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On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The hearing ~~for this rate case is currently scheduled to begin in July 2020.~~began January 14, 2021. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome of ~~its request.~~this proceeding.

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2016 Retail Rate Case Filing with the Arizona Corporation Commission

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the ~~"2017~~“2017 Settlement ~~Agreement"~~Agreement”) and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

~~an agreement by APS not to file another general retail rate case application before June 1, 2019;~~

•an authorized return on common equity of 10.0%;

•a capital structure comprised of 44.2% debt and 55.8% common equity;

•a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

•a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;

•a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

•an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;

•a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ~~("DG"~~(“DG”) with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;

•an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

•rate design changes, including:


▪	~~a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;~~


▪	~~non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;~~


▪	~~a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~▪a change in the on-peak time of use period from noon-7 p.m. to 3 p.m.-8 p.m. Monday through Friday, excluding holidays;

▪non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;

▪a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

•an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

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On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the ~~"2017~~“2017 Rate Case ~~Decision"~~Decision”), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least NaN customers of the public service corporation.. The Complaint ~~alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an~~was later amended ~~Complaint~~ alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter, ~~beginning in September 2018~~ and ~~the hearing was concluded on October 1, 2018. On April 9, 2019,~~ the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. ~~The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued.~~ On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC ~~reconsidered the matter and~~ adopted the Administrative Law ~~Judge's~~Judge’s amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.

ACC Review of APS 2017 Rate Case Decision

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test ~~year and file a report by May 3, 2019.~~year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. ~~On April 23, 2019, the ACC Staff indicated that they would need additional time beyond May 3, 2019 to file the requested report.~~

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

•APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

•until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;

•APS customers can switch rate plans during an open enrollment period of six months;

•APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;

•APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;

•APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and

•APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see

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below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

APS ~~cannot predict the outcome or impact of the~~filed its rate case ~~filed~~ on October 31, ~~2019.~~2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS ~~is assessing the impact to its financial statements of~~does not believe that the implementation of the other key provisions of the amended order regarding the rate review ~~and cannot predict at this time whether they~~ will have a material impact on its financial position, results of operations or cash flows.

On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. APS is monitoring this matter, but believes that the proposals are not legal and further that APS has not over-earned. The ACC voted to administratively close this docket on November 4, 2020.

Cost Recovery Mechanisms

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.

Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request was lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for 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

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

carrying costs for this program will be recovered through the RES. ~~On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver~~

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On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.

On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2021 contained in the RES rules. In the 2021 RES Implementation Plan, APS requests $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. The ACC has not yet ruled on the ~~2020~~2021 RES Implementation Plan.

On July ~~2, 2019,~~15, 2020, ACC Staff issued final draft rules which, ~~propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand~~if approved, would require APS to ~~be from~~meet certain clean energy ~~resources by 2035. The draft rules would also require~~standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. See "Energy Modernization Plan" below for more information.

On January 8, 2020, an ACC commissioner proposed replacing the current RES standard with a new standard ("KREST II"). KREST II sets a RES goal of 50% of retail energy to be served by renewables by 2028, 100% zero carbon resources by 2045, and a 35% energy efficiency resource standard by 2030 with a 10% demand response carve out.rate process. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” below for more information.

Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan ("(“DSM ~~Plan"~~Plan”) annually for review by and approval of the ACC. Verified energy savings from ~~APS's~~APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism (see below for discussion of the LFCR).

On September 1, 2017, APS filed its 2018 DSM Plan, which ~~proposes~~proposed modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan ~~seeks~~sought a requested budget of $52.6 million and ~~requests~~requested a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. ~~The ACC has not yet ruled on the APS 2018 amended DSM Plan.~~

On December 31, 2018, APS filed its 2019 DSM Plan, which ~~requests~~requested a budget of $34.1 million and ~~continues APS's focus~~focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies. ~~The ACC has not yet ruled on the APS 2019 DSM Plan.~~

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On December 31, 2019, APS filed its 2020 DSM Plan, which ~~requests~~requested a budget of $51.9 million and ~~continues APS's~~continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan ~~addresses~~addressed all components of the pending 2018 and 2019 DSM plans,

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

which ~~enables~~enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See “COVID-19 Pandemic” above for more information.

On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continues APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. The ACC has not yet ruled on the APS ~~2020~~2021 DSM Plan.

Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

An•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

~~The~~•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

~~The~~•the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

~~The~~•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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The following table shows the changes in the deferred fuel and purchased power regulatory asset for ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Twelve Months Ended December 31,
	2020		2019
Beginning balance	$	70,137	$	37,164
Deferred fuel and purchased power costs — current period	93,651		82,481
Amounts refunded/(charged) to customers	12,047		(49,508)
Ending balance	$	175,835	$	70,137

Twelve Months Ended
December 31,
2019 2018
Beginning balance $ 37,164
$ 75,637
Deferred fuel and purchased power costs — current period 82,481
78,277
Amounts charged to customers (49,508 ) (116,750 )
Ending balance $ 70,137
$ 37,164

The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a Forward Component of $0.002009 per kWh and a Historical Component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The PSA rate for the PSA year beginning February 1, 2019 iswas $0.001658 per kWh, ~~consisting~~as compared to the $0.004555 per kWh for the prior year. This rate was comprised of a ~~Forward Component~~forward component of $0.000536 per kWh and a ~~Historical Component~~historical component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018.

These rates went into effect as filed on February 1, 2019.

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh and consisted of a ~~Forward Component~~forward component of $(0.002086) per kWh and a ~~Historical Component~~historical component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020.

On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021.That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh.The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021.

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to 2 energy storage power purchase tolling agreements through the PSA. ~~This application is pending with~~On December 29, 2020, the ~~ACC. APS cannot predict~~ACC Staff filed its report and recommended the ~~outcome of~~storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this ~~matter.~~

application.

Environmental Improvement Surcharge ~~("EIS"~~(“EIS”). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February ~~1st~~1 for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC. There is an overall cap of $0.0005 per kWh (approximately $13 -million to 14 million per year). APS’s February 1, ~~2020~~2021 application requested an increase in the charge to ~~$8.75~~$10.3 million, or ~~$2.0~~$1.5 million over the charge in effect for the ~~2019-2020~~2020-2021 rate effective year.

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve ~~APS's~~APS’s retail customers ("(“Retail Transmission ~~Charges"~~Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain

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approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding ~~APS's~~APS’s rate case ("(“2012 Settlement ~~Agreement"~~Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of ~~APS's~~APS’s actual cost of service, as disclosed in ~~APS's~~APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Effective June 1, 2018, ~~APS's~~APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the ~~FERC approved~~FERC-approved formula. Of this amount, retail customer rates decreased by approximately $26.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately ~~$4.9~~$25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

Effective June 1, 2020, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula. Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement toare currently 2.5 cents for both lost residential and non-residential ~~kWh.~~kWh as set forth in the 2017 Settlement Agreement. The LFCR adjustment has a year-over-year cap of 1%

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of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.

On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020. On February 15, 2021, APS ~~cannot predict~~filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the ~~outcome or timing of the ACC’s consideration of this filing. Because the~~annual LFCR ~~mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS.~~

recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels).

Tax Expense Adjustor Mechanism. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to ~~APS's~~APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("(“TEAM Phase I"I”). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("(“TEAM Phase ~~II"~~II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the ~~final~~last billing cycle ofin March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS’s 2019 retail rate case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.

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On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. ~~It is currently anticipated that benefits related~~On November 20, 2020, APS filed an application to continue the ~~amortization~~TEAM Phase III monthly bill credit through the earlier of ~~depreciation related excess deferred taxes for periods beginning after~~ December 31, 2021, or at the conclusion of APS’s 2019 pending rate case. On December 9, 2020, ~~will be fully incorporated into~~ the ~~2019 rate case filing.~~ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are recognized based upon APS’s seasonal kWh sales pattern.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology ~~is developed by the ACC~~.

~~As amended, the decision~~ provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in ~~APS's~~APS’s subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

In addition, the ACC made the following determinations:

~~Customers~~•customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on ~~APS's~~APS’s 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

~~Customers~~•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

~~Once~~•once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019. This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On

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September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. APS’s export energy price will remain at 10.5 cents per kWh until October 1, 2021.

On January 23, 2017, The Alliance for Solar Choice ~~("TASC"~~(“TASC”) sought rehearing of the ~~ACC's~~ACC’s decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

See ~~"2016~~“2016 Retail Rate Case Filing with the Arizona Corporation ~~Commission"~~Commission” above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.

Subpoena from Former Arizona Corporation Commissioner Robert Burns

On August 25, 2016, ~~Commissioner~~then-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay ~~APS's~~APS’s obligations to comply with the subpoenas and decline to decide ~~APS's~~APS’s motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that ~~Commissioner~~ Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, ~~Commissioner~~ Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff. As part of this docket, ~~Commissioner~~ Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, ~~Commissioner~~ Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss ~~Commissioner Burns'~~Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the

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court stayed the suit and ordered ~~Commissioner~~ Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, ~~Commissioner~~ Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed ~~Commissioner~~ Burns’ amended complaint. On March 6, 2018, ~~Commissioner~~ Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted ~~Commissioner~~ Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. ~~Commissioner~~ Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019.

On February 13, 2019, ~~Commissioner~~ Burns filed a notice of appeal. On July 12, 2019, ~~Commissioner~~ Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument ~~but no date~~given the COVID-19 pandemic. The court determined that the matter could be submitted without oral argument and has ~~been set.~~taken the matter under advisement and will issue a decision without oral argument.

Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. Pinnacle West and APS cannot predict the outcome of this matter.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The ~~Company's~~Company’s CEO, Mr. Guldner, appeared at the ~~ACC's~~ACC’s January 14, 2020 Open Meeting regarding ACC ~~Commissioners'~~Commissioners’ questions about political spending. Mr. Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

~~2018 Renewable Energy Ballot Initiative~~

On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan ~~("IRP"~~

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(“IRP”) process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.

On April 25, 2019, the ACC Staff issued aan initial set of draft energy rules ~~in regards~~and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the ~~Energy Modernization Plan and workshops were held on April 29, 2019 regarding these~~March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft ~~rules.~~of proposed rules by July 2020. On July ~~2, 2019,~~30, 2020, the ACC Staff issued ~~a revised set of~~final draft energy rules which ~~propose~~proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a ~~RES goal of 45%~~clean energy resource. The proposed rules also require 50% of retail energy served be renewable by ~~2035 and a goal~~the end of ~~20% of retail sales during peak demand to be from clean~~2035. A new energy ~~resources by 2035. The draft rules also require a certain amount of~~efficiency standard was not included in the ~~RES goal to be derived from distributed renewable storage, for which utilities~~proposed rules. APS would be required to ~~offer performance-based incentives. Nuclear energy~~obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would ~~be considered~~require utilities to file a ~~clean resource under~~Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, the ~~draft rules.~~ ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.

The ACC ~~held various stakeholder meetings and workshops on ACC Staff’s~~has discussed the final draft energy rules at several different meetings in ~~July through September 2019 and have scheduled a workshop to be held on March 10 - 11,~~ 2020. On ~~February 19,~~October 14, 2020, the ACC ~~Staff issued a revised proposed set of~~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; 75% by 2040; and 100% by 2050. The ACC also approved an amendment that 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 ~~discussed at~~derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the ~~workshop.~~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.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Integrated Resource Planning

ACC rules require utilities to develop ~~fifteen-year~~15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary 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. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s 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. The ACC has taken no

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action on APS’s IRP. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.

Public Utility Regulatory Policies Act

~~In August 2016, APS filed an application requesting that all~~Under the Public Utility Regulatory Policies Act of ~~its contracts with~~1978 (“PURPA”), qualifying facilities over 100 kW be set at a presumptive maximum 2-year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has aare provided the right to sell energy and/or capacity to ~~the host utility. Host~~ utilities and are ~~required to purchase power~~granted relief from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application.certain regulatory burdens. On December 17, 2019, the ACC ~~denied the application and~~ mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to ~~the~~ qualifying facilities ~~will~~must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into 2 18-year power purchase agreements with qualified facilities, each for 80 MW solar facilities. These agreements are pending ACC approval.

On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020. APS is evaluating how the revised regulations may impact its operations.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period ~~from~~ June 1 through October ~~15.~~15 (“Summer Disconnection Moratorium”). During the ~~moratorium on disconnections,~~Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. ~~The~~Although the emergency ~~rule changes~~rules expired in December 2019, the Summer Disconnection Moratorium will ~~be effective~~remain in effect through utility tariffs for ~~180 days~~2021 and ~~may be renewed for one additional 180 day period. During that time,~~beyond until the ACC adopts permanent rules or determines otherwise.

In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment until December 31, 2020. The suspension of disconnection ~~moratorium resulted in a negative impact~~of customers for nonpayment ended on January 1, 2021 and customers were placed automatically on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to ~~our 2019 operating results~~waive late payment fees until October 15, 2021. The Summer Disconnection Moratorium, the suspension of ~~approximately $10 million pre-tax. APS is further assessing~~disconnections during the ~~impact to its financial statements beyond 2019, which will be affected by~~COVID-19 pandemic and the ~~results~~increased bad debt

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expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. See “COVID-19 Pandemic” above for more information.

Retail Electric Competition Rules

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~~Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC ~~has scheduled~~held a workshop ~~for~~on February 25-26, 2020 ~~for~~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. 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.

Rate Plan Comparison Tool and Investigation

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and ~~the Company’s~~APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation ~~that would result in the lowest bills~~ based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. By the middle of May 2020, APS ~~is providing~~provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided isdid not ~~expected to~~ have a material impact on ~~APS's~~APS’s financial statements. APS developed a new tool for comparing customers’ rate plan options. APS had an independent third party verify that the new rate comparison tool works correctly. In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is ~~currently investigating~~working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this ~~matter.~~ report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.

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APS received a civil investigative ~~demand~~demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section ~~that seeks~~(“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS ~~customers.~~customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS is fully ~~cooperating~~cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ~~outcome of these matters.~~ ACC.

Four Corners

~~SCE-Related Matters~~. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provide transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

of 2016. On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. On December 18, 2019, APS submitted an offer of settlement to FERC to resolve all outstanding issues related to this matter. The offer of settlement provided that APS would not recover in rates any portion of any payment it made to SCE in connection with the expiration of the Transmission Agreement and FERC would close certain dockets related to this matter. On February 5, 2020, FERC issued an order accepting APS’s offer of settlement and resolved this matter.

SCR Cost Recovery

On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC ~~Staff's~~Staff’s recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 ~~retail rate case~~Retail Rate Case filing with the ACC. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla 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~~APS’s plan to retire Unit 2, without expressing any view on the future recoverability of ~~APS's~~APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating ~~APS's~~APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it ~~plans~~planned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 2020.

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Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

decommissioning and other retirement-related costs ($7357 million as of December 31, ~~2019)~~2020), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.

Navajo Plant

The ~~co-owners of the~~ Navajo Plant ~~and the Navajo Nation agreed that the Navajo Plant would remain~~ceased operations in ~~operation until December 2019 under the existing plant lease.~~November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased ~~operations in November 2019.~~operations.

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 ($8272 million as of December 31, ~~2019)~~2020) plus a return on the net book value as well as other costs related to retirement and closure, ~~which are still being assessed and may be material.~~including the Navajo coal reclamation regulatory asset ($18 million as of December 31, 2020). APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, ~~APS's~~APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and ~~APS's~~APS’s net income, cash flows, and financial position will be negatively impacted.

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Regulatory Assets and Liabilities

The detail of regulatory assets is as follows (dollars in thousands):


S		December 31, 2020				December 31, 2019
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	0	$	469,953	$	0	$	660,223
Deferred fuel and purchased power (b) (c)	2021	175,835		0		70,137		0
Income taxes — AFUDC equity	2050	7,169		158,776		6,800		154,974
Retired power plant costs	2033	28,181		114,214		28,182		142,503
Ocotillo deferral	N/A	0		95,723		0		38,144
SCR deferral	N/A	0		81,307		0		52,644
Deferred property taxes	2027	8,569		49,626		8,569		58,196
Lost fixed cost recovery (b)	2021	41,807		0		26,067		0
Deferred compensation	2036	0		36,195		0		36,464
Four Corners cost deferral	2024	8,077		24,075		8,077		32,152
Income taxes — investment tax credit basis adjustment	2049	1,113		24,291		1,098		24,981
Palo Verde VIEs (Note 18)	2046	0		21,255		0		20,635
Coal reclamation	2026	1,068		16,999		1,546		17,688
Deferred fuel and purchased power — mark-to-market (Note 16)	2024	3,341		9,244		36,887		33,185
Loss on reacquired debt	2038	1,689		10,877		1,637		12,031
Mead-Phoenix transmission line — contributions in aid of construction	2050	332		9,380		332		9,712
Demand side management (b)	2022	0		7,268		0		0
Tax expense adjustor mechanism (b)	2021	6,226		0		1,612		0
Tax expense of Medicare subsidy	2024	1,235		3,704		1,235		4,940
PSA interest	2021	4,355		0		1,917		0
TCA balancing account (b)	2021	0		0		6,324		2,885
Other	Various	2,716		1,100		2,787		2,716
Total regulatory assets (d)		$	291,713	$	1,133,987	$	203,207	$	1,304,073

(a)This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (See Note 8 for further discussion.)

(b)See “Cost Recovery Mechanisms�� discussion above.

(c)Subject to a carrying charge.

(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

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S December 31, 2019 December 31, 2018
Amortization Through Current Non-Current Current Non-Current
Pension (a) $ —
$ 660,223
$ —
$ 733,351
Retired power plant costs 2033 28,182
142,503
28,182
167,164
Income taxes - AFUDC equity 2049 6,800
154,974
6,457
151,467
Deferred fuel and purchased power (b) (c) 2020 70,137
—
37,164
—
Deferred fuel and purchased power — mark-to-market (Note 17) 2024 36,887
33,185
31,728
23,768
Deferred property taxes 2027 8,569
58,196
8,569
66,356
SCR deferral N/A —
52,644
—
23,276
Four Corners cost deferral 2024 8,077
32,152
8,077
40,228
Ocotillo deferral N/A —
38,144
—
—
Deferred compensation 2036 —
36,464
—
36,523
Income taxes — investment tax credit basis adjustment 2048 1,098
24,981
1,079
25,522
Lost fixed cost recovery (b) 2020 26,067
—
32,435
—
Palo Verde VIEs (Note 19) 2046 —
20,635
—
20,015
Coal reclamation 2026 1,546
17,688
1,546
15,607
Loss on reacquired debt 2038 1,637
12,031
1,637
13,668
Mead-Phoenix transmission line - contributions in aid of construction 2050 332
9,712
332
10,044
TCA balancing account (b) 2021 6,324
2,885
3,860
772
Tax expense of Medicare subsidy 2024 1,235
4,940
1,235
6,176
AG-1 deferral 2022 2,787
2,716
2,654
5,819
Tax expense adjustor mechanism (b) 2020 1,612
—
—
—
Other Various 1,917
—
1,947
3,185
Total regulatory assets (d) $ 203,207
$ 1,304,073
$ 166,902
$ 1,342,941

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~~(a)~~	This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. See Note 8 for further discussion.


~~(b)~~	~~See “Cost Recovery Mechanisms” discussion above.~~


~~(c)~~	~~Subject to a carrying charge.~~


~~(d)~~	There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The detail of regulatory liabilities is as follows (dollars in thousands):


		December 31, 2020				December 31, 2019
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)	2046	$	41,330	$	1,012,583	$	59,918	$	1,054,053
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)	2058	7,240		229,147		6,302		237,357
Asset retirement obligations	2057	0		506,049		0		418,423
Other postretirement benefits	(d)	37,705		349,588		37,575		139,634
Removal costs	(c)	52,844		103,008		47,356		136,072
Income taxes — change in rates	2050	2,839		66,553		2,797		68,265
Four Corners coal reclamation	2038	5,460		49,435		1,059		51,704
Spent nuclear fuel	2027	6,768		44,221		6,676		51,019
Income taxes — deferred investment tax credit	2049	2,231		48,648		2,202		50,034
Renewable energy standard (b)	2021	39,442		103		39,287		10,300
Sundance maintenance	2031	2,989		11,508		5,698		11,319
Property tax deferral	N/A	0		13,856		0		7,046
Demand side management (b)	2021	10,819		0		15,024		24,146
FERC transmission true up	2022	6,598		3,008		1,045		2,004
TCA balancing account (b)	2022	2,902		4,672		0		0
Tax expense adjustor mechanism (b) (e)	2021	7,089		0		7,018		0
Active union medical trust	N/A	0		6,057		0		2,041
Deferred gains on utility property	2022	2,423		1,544		2,423		4,163
Other	Various	409		189		532		255
Total regulatory liabilities		$	229,088	$	2,450,169	$	234,912	$	2,267,835

(a)For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.

(b)See “Cost Recovery Mechanisms” discussion above.

(c)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(d)See Note 8.

(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.

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December 31, 2019 December 31, 2018
Amortization Through Current Non-Current Current Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a) 2046 $ 59,918
$ 1,054,053
$ —
$ 1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a) 2058 6,302
237,357
6,302
243,691
Asset retirement obligations 2057 —
418,423
—
278,585
Removal costs (c) 47,356
136,072
39,866
177,533
Other postretirement benefits (d) 37,575
139,634
37,864
125,903
Income taxes - change in rates 2049 2,797
68,265
2,769
70,069
Spent nuclear fuel 2027 6,676
51,019
6,503
57,002
Four Corners coal reclamation 2038 1,059
51,704
1,858
17,871
Income taxes - deferred investment tax credit 2048 2,202
50,034
2,164
51,120
Renewable energy standard (b) 2021 39,287
10,300
44,966
20
Demand side management (b) 2021 15,024
24,146
14,604
4,123
Sundance maintenance 2031 5,698
11,319
1,278
17,228
Property tax deferral N/A —
7,046
—
2,611
Tax expense adjustor mechanism (b) 2020 7,018
—
3,237
—
Deferred gains on utility property 2022 2,423
4,163
4,423
6,581
FERC transmission true up 2021 1,045
2,004
—
—
Other Various 532
2,296
42
930
Total regulatory liabilities $ 234,912
$ 2,267,835
$ 165,876
$ 2,325,976


~~(a)~~	For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities.


~~(b)~~	~~See “Cost Recovery Mechanisms” discussion above.~~


~~(c)~~	~~In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.~~


~~(d)~~	~~See Note 8.~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates.

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of ~~the balance~~this net regulatory liability over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the ~~Company's~~Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. ~~As of December 31, 2019, the~~The Company ~~has~~ recorded $14 million and $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax ~~liabilities.~~liabilities in 2020 and 2019, respectively. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. ~~As a result, in the fourth quarter of 2019, the~~The Company ~~has~~ recorded $31 million and $62 million of income tax benefit related to amortization of these depreciation related ~~liabilities. See~~liabilities in 2020 and 2019, respectively. (See Note 4 for more details.)

In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

~~Along with the~~In September ~~2019 final regulations,~~2020, U.S. Treasury ~~also~~ issued ~~new proposed~~final regulations, which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The ~~proposed~~final regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 ~~would continue~~continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. ~~During the third quarter of 2019, as a result of the clarification provided~~These final regulations do not materially impact any tax position taken by ~~these proposed regulations,~~ the Company ~~recorded additional deferred tax liabilities~~for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.

139

Table of ~~approximately $56 million related to bonus depreciation benefits claimed on the Company’s 2018 tax return.~~Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the ~~statement~~Statements of ~~income.~~Income.

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is 0 income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. ~~See~~(See Note 1918 for additional details related to the Palo Verde sale leaseback VIEs.)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):


	Pinnacle West Consolidated						APS Consolidated
	2020		2019		2018		2020		2019		2018
Total unrecognized tax benefits, January 1	$	43,435	$	40,731	$	41,966	$	43,435	$	40,731	$	41,966
Additions for tax positions of the current year	3,418		3,373		3,436		3,418		3,373		3,436
Additions for tax positions of prior years	1,431		1,843		2,696		1,431		1,843		2,696
Reductions for tax positions of prior years for:
Changes in judgment	(1,965)		(2,078)		(1,764)		(1,965)		(2,078)		(1,764)
Settlements with taxing authorities	0		0		0		0		0		0
Lapses of applicable statute of limitations	(664)		(434)		(5,603)		(664)		(434)		(5,603)
Total unrecognized tax benefits, December 31	$	45,655	$	43,435	$	40,731	$	45,655	$	43,435	$	40,731

Pinnacle West Consolidated APS Consolidated
2019 2018 2017 2019 2018 2017
Total unrecognized tax benefits, January 1 $ 40,731
$ 41,966
$ 36,075
$ 40,731
$ 41,966
$ 36,075
Additions for tax positions of the current year 3,373
3,436
2,937
3,373
3,436
2,937
Additions for tax positions of prior years 1,843
2,696
4,783
1,843
2,696
4,783
Reductions for tax positions of prior years for:

Changes in judgment (2,078 ) (1,764 ) (1,829 ) (2,078 ) (1,764 ) (1,829 )
Settlements with taxing authorities —
—
—
—
—
—
Lapses of applicable statute of limitations (434 ) (5,603 ) —
(434 ) (5,603 ) —
Total unrecognized tax benefits, December 31 $ 43,435
$ 40,731
$ 41,966
$ 43,435
$ 40,731
$ 41,966

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

Pinnacle West Consolidated APS Consolidated
2019 2018 2017 2019 2018 2017
Tax positions, that if recognized, would decrease our effective tax rate $ 22,813
$ 19,504
$ 16,373
$ 22,813
$ 19,504
$ 16,373


	Pinnacle West Consolidated						APS Consolidated
	2020		2019		2018		2020		2019		2018
Tax positions, that if recognized, would decrease our effective tax rate	$	25,714	$	22,813	$	19,504	$	25,714	$	22,813	$	19,504

As of the balance sheet date, the tax year ended December 31, ~~2016~~2017 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before ~~2015.~~2016.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):


	Pinnacle West Consolidated						APS Consolidated
	2020		2019		2018		2020		2019		2018
Unrecognized tax benefit interest expense/(benefit) recognized	$	266	$	459	$	(780)	$	266	$	459	$	(780)

140

Pinnacle West Consolidated APS Consolidated
2019 2018 2017 2019 2018 2017
Unrecognized tax benefit interest expense/(benefit) recognized $ 459
$ (780 ) $ 577
$ 459
$ (780 ) $ 577

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

Pinnacle West Consolidated APS Consolidated
2019 2018 2017 2019 2018 2017
Unrecognized tax benefit interest accrued $ 1,589
$ 1,130
$ 1,910
$ 1,589
$ 1,130
$ 1,910

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~


	Pinnacle West Consolidated						APS Consolidated
	2020		2019		2018		2020		2019		2018
Unrecognized tax benefit interest accrued	$	1,855	$	1,589	$	1,130	$	1,855	$	1,589	$	1,130

Additionally, as of December 31, ~~2019,~~2020, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):


	Pinnacle West Consolidated						APS Consolidated
	Year Ended December 31,						Year Ended December 31,
	2020		2019		2018		2020		2019		2018
Current:
Federal	$	11,869	$	(13,551)	$	18,375	$	57,299	$	(54,697)	$	88,180
State	1,932		3,195		3,342		99		695		1,877
Total current	13,801		(10,356)		21,717		57,398		(54,002)		90,057
Deferred:
Federal	53,398		(14,982)		94,721		15,122		29,321		32,436
State	10,974		9,565		17,464		16,244		15,109		22,321
Total deferred	64,372		(5,417)		112,185		31,366		44,430		54,757
Income tax expense/(benefit)	$	78,173	$	(15,773)	$	133,902	$	88,764	$	(9,572)	$	144,814

Pinnacle West Consolidated APS Consolidated
Year Ended December 31, Year Ended December 31,
2019 2018 2017 2019 2018 2017
Current:

Federal $ (13,551 ) $ 18,375
$ 11,624
$ (54,697 ) $ 88,180
$ 21,512
State 3,195
3,342
3,052
695
1,877
2,778
Total current (10,356 ) 21,717
14,676
(54,002 ) 90,057
24,290
Deferred:

Federal (14,982 ) 94,721
223,729
29,321
32,436
221,078
State 9,565
17,464
19,867
15,109
22,321
23,800
Total deferred (5,417 ) 112,185
243,596
44,430
54,757
244,878
Income tax expense/(benefit) $ (15,773 ) $ 133,902
$ 258,272
$ (9,572 ) $ 144,814
$ 269,168

The following chart compares pretax income at the 21% statutory federal income tax rate ~~of 21% in 2019 and 2018 and 35% in 2017~~ to income tax expense (dollars in thousands):


	Pinnacle West Consolidated						APS Consolidated
	Year Ended December 31,						Year Ended December 31,
	2020		2019		2018		2020		2019		2018
Federal income tax expense at statutory rate	$	136,127	$	113,828	$	139,533	$	142,020	$	120,790	$	154,260
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	19,146		18,599		23,115		20,124		19,267		24,531
State income tax credits net of federal income tax benefit	(8,951)		(8,519)		(6,704)		(7,213)		(6,781)		(5,440)
Nondeductible expenditures associated with ballot initiative	0		0		7,879		0		0		0

Stock compensation	34		(2,252)		(1,804)		183		(1,054)		(780)
Excess deferred income taxes — Tax Cuts and Jobs Act	(50,543)		(124,082)		(6,725)		(50,543)		(124,082)		(4,715)
Allowance for equity funds used during construction (see Note 1)	(2,747)		(2,476)		(7,231)		(2,747)		(2,476)		(7,231)
Palo Verde VIE noncontrolling interest (see Note 18)	(4,094)		(4,094)		(4,094)		(4,094)		(4,094)		(4,094)
Investment tax credit amortization	(7,510)		(6,851)		(6,742)		(7,510)		(6,851)		(6,742)
Other	(3,289)		74		(3,325)		(1,456)		(4,291)		(4,975)
Income tax expense/(benefit)	$	78,173	$	(15,773)	$	133,902	$	88,764	$	(9,572)	$	144,814

Pinnacle West Consolidated APS Consolidated
Year Ended December 31, Year Ended December 31,
2019 2018 2017 2019 2018 2017
Federal income tax expense at statutory rate $ 113,828
$ 139,533
$ 268,177
$ 120,790
$ 154,260
$ 277,540
Increases (reductions) in tax expense resulting from:

State income tax net of federal income tax benefit 18,599
23,115
21,380
19,267
24,531
22,329
State income tax credits net of federal income tax benefit (8,519 ) (6,704 ) (6,483 ) (6,781 ) (5,440 ) (5,053 )
Nondeductible expenditures associated with ballot initiative —
7,879
—
—
—
—
Stock compensation (2,252 ) (1,804 ) (6,659 ) (1,054 ) (780 ) (3,489 )
Excess deferred income taxes - Tax Cuts and Jobs Act (124,082 ) (6,725 ) 9,348
(124,082 ) (4,715 ) 9,431
Allowance for equity funds used during construction (see Note 1) (2,476 ) (7,231 ) (12,937 ) (2,476 ) (7,231 ) (12,937 )
Palo Verde VIE noncontrolling interest (see Note 19) (4,094 ) (4,094 ) (6,823 ) (4,094 ) (4,094 ) (6,823 )
Investment tax credit amortization (6,851 ) (6,742 ) (6,715 ) (6,851 ) (6,742 ) (6,715 )
Other 74
(3,325 ) (1,016 ) (4,291 ) (4,975 ) (5,115 )
Income tax expense/(benefit) $ (15,773 ) $ 133,902
$ 258,272
$ (9,572 ) $ 144,814
$ 269,168

141

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of the net deferred income tax liability were as follows (dollars in thousands):

Pinnacle West Consolidated APS Consolidated
December 31, December 31,
2019 2018 2019 2018
DEFERRED TAX ASSETS

Risk management activities $ 17,552
$ 15,785
$ 17,552
$ 15,785
Regulatory liabilities:

Excess deferred income taxes - Tax Cuts and Jobs Act 335,877
376,869
335,877
376,869
Asset retirement obligation and removal costs 143,011
117,201
143,011
117,201
Unamortized investment tax credits 52,236
53,284
52,236
53,284
Other postretirement benefits 43,841
40,532
43,841
40,532
Other 52,382
40,380
52,382
40,380
Pension liabilities 73,210
112,019
67,976
107,009
Coal reclamation liabilities 40,837
47,508
40,837
47,508
Renewable energy incentives 28,066
30,779
28,066
30,779
Credit and loss carryforwards 54,795
1,755
10,992
—
Other 63,102
58,820
70,948
59,919
Total deferred tax assets 904,909
894,932
863,718
889,266
DEFERRED TAX LIABILITIES

Plant-related (2,448,458 ) (2,277,724 ) (2,448,458 ) (2,277,724 )
Risk management activities (27 ) (237 ) (27 ) (237 )
Other postretirement assets and other special use funds (66,399 ) (57,697 ) (65,965 ) (57,274 )
Regulatory assets:

Allowance for equity funds used during construction (40,023 ) (39,086 ) (40,023 ) (39,086 )
Deferred fuel and purchased power (35,162 ) (23,086 ) (35,162 ) (23,086 )
Pension benefits (163,339 ) (181,504 ) (163,339 ) (181,504 )
Retired power plant costs (see Note 4) (42,228 ) (48,348 ) (42,228 ) (48,348 )
Other (82,722 ) (72,096 ) (82,722 ) (72,096 )
Other (18,890 ) (2,575 ) (18,890 ) (2,575 )
Total deferred tax liabilities (2,897,248 ) (2,702,353 ) (2,896,814 ) (2,701,930 )
Deferred income taxes — net $ (1,992,339 ) $ (1,807,421 ) $ (2,033,096 ) $ (1,812,664 )


	Pinnacle West Consolidated				APS Consolidated
	December 31,				December 31,
	2020		2019		2020		2019
DEFERRED TAX ASSETS
Risk management activities	$	4,287	$	17,552	$	4,287	$	17,552
Regulatory liabilities:
Excess deferred income taxes — Tax Cuts and Jobs Act	319,091		335,877		319,091		335,877
Asset retirement obligation and removal costs	157,470		143,011		157,470		143,011
Unamortized investment tax credits	50,879		52,236		50,879		52,236
Other postretirement benefits	95,778		43,841		95,778		43,841
Other	43,551		52,382		43,551		52,382
Operating lease liabilities	107,853		15,497		107,414		15,497
Pension liabilities	45,853		73,210		40,168		67,976
Coal reclamation liabilities	42,065		40,837		42,065		40,837
Renewable energy incentives	25,355		28,066		25,355		28,066
Credit and loss carryforwards	26,460		54,795		8,034		10,992
Other	78,113		47,605		78,113		55,451
Total deferred tax assets	996,755		904,909		972,205		863,718
DEFERRED TAX LIABILITIES
Plant-related	(2,489,899)		(2,448,458)		(2,489,899)		(2,448,458)
Risk management activities	(1,174)		(27)		(1,174)		(27)
Pension and other postretirement assets	(123,462)		(21,892)		(122,580)		(21,458)
Other special use funds	(42,927)		(44,507)		(42,927)		(44,507)
Operating lease right-of-use assets	(107,853)		(15,497)		(107,414)		(15,497)
Regulatory assets:
Allowance for equity funds used during construction	(41,038)		(40,023)		(41,038)		(40,023)
Deferred fuel and purchased power	(47,673)		(35,162)		(47,673)		(35,162)
Pension benefits	(116,219)		(163,339)		(116,219)		(163,339)
Retired power plant costs	(35,214)		(42,228)		(35,214)		(42,228)
Other	(106,227)		(82,722)		(106,227)		(82,722)
Other	(20,472)		(3,393)		(5,513)		(3,393)
Total deferred tax liabilities	(3,132,158)		(2,897,248)		(3,115,878)		(2,896,814)
Deferred income taxes — net	$	(2,135,403)	$	(1,992,339)	$	(2,143,673)	$	(2,033,096)

As of December 31, ~~2019, the~~2020, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately ~~$62~~$35 million, which first begin to expire in 2036 and state credit carryforwards net of federal benefit of ~~$23~~$33 million, which first begin to expire in ~~2023, and other federal carryforwards of~~ ~~$9 million. The~~2023. PNW Consolidated credit and loss carryforwards amount above has been reduced by ~~$39~~$42 million of unrecognized tax benefits.

As of December 31, 2020, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $16 million, which first begin to expire in 2024. APS Consolidated credit and loss carryforwards amount above has been reduced by $8 million of unrecognized tax benefits.

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6. Lines of Credit and Short-Term Borrowings

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate ~~purposes~~.purposes.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	December 31, 2020						December 31, 2019
	Pinnacle West		APS		Total		Pinnacle West		APS		Total
Commitments under Credit Facilities	$	231,000	$	1,000,000	$	1,231,000	$	250,000	$	1,000,000	$	1,250,000
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings	(169,000)		0		(169,000)		(114,675)		0		(114,675)
Amount of Credit Facilities Available	$	62,000	$	1,000,000	$	1,062,000	$	135,325	$	1,000,000	$	1,135,325

Weighted-Average Commitment Fees	0.125%		0.100%				0.125%		0.100%

December 31, 2019 December 31, 2018
Pinnacle West APS Total Pinnacle West APS Total
Commitments under Credit Facilities $ 200,000
$ 1,000,000
$ 1,200,000
$ 350,000
$ 1,000,000
$ 1,350,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings (76,675 ) —
(76,675 ) (76,400 ) —
(76,400 )
Amount of Credit Facilities Available $ 123,325
$ 1,000,000
$ 1,123,325
$ 273,600
$ 1,000,000
$ 1,273,600

Weighted-Average Commitment Fees 0.125% 0.100% 0.125% 0.100%

Pinnacle West

On May ~~9, 2019,~~5, 2020, Pinnacle West ~~entered into~~refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a ~~$50~~new 364-day $31 million term loan agreement that matures May ~~7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility.~~4, 2021. Borrowings under the agreement bear interest at ~~London Inter-bank Offered~~Eurodollar Rate ~~("LIBOR")~~ plus ~~0.55%~~1.40% per annum. At December 31, ~~2019,~~2020, Pinnacle West had ~~$38~~$19 millionin outstanding borrowings under the agreement.

At December 31, ~~2019,~~2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle ~~West's~~West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle ~~West's~~West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, ~~2019,~~2020, Pinnacle West had 0 outstanding borrowings under its credit facility, 0 letters of credit outstanding and ~~$77~~$150 million of commercial paper borrowings.

APS

At December 31, ~~2019,~~2020, APS had 2 revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, ~~2019,~~2020, APS had 0 ~~commercial paper outstanding and 0~~ outstanding borrowings ~~or letters of credit~~ under its revolving credit ~~facilities.~~ facilities, 0 letters of credit outstanding or commercial paper borrowings.

See ~~"Financial Assurances"~~“Financial Assurances” in Note 11 for a discussion of ~~APS's~~APS’s other outstanding letters of credit.

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Debt Provisions

On ~~November 27, 2018,~~December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). ~~See~~(See Note 7 for additional long-term debt provisions.)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

7. Long-Term Debt and Liquidity Matters

All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Maturity	Interest	December 31,
	Dates (a)	Rates	2020		2019
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975	$	35,975
Fixed	2024	4.70%	0		115,150
Total pollution control bonds			35,975		151,125
Senior unsecured notes	2024-2050	2.55%-6.88%	5,830,000		4,875,000
Term loans		(c)	0		200,000
Unamortized discount			(15,900)		(12,434)
Unamortized premium			14,781		7,423
Unamortized debt issuance cost			(46,911)		(37,981)
Total APS long-term debt			5,817,945		5,183,133
Less current maturities			0		350,000
Total APS long-term debt less current maturities			5,817,945		4,833,133
Pinnacle West
Senior unsecured notes	2025	1.3%	500,000		300,000
Term loan		(d)	0		150,000
Unamortized discount			(44)		(57)
Unamortized debt issuance cost			(3,635)		(518)
Total Pinnacle West long-term debt			496,321		449,425
Less current maturities			0		450,000
Total Pinnacle West long-term debt less current maturities			496,321		(575)
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	6,314,266	$	4,832,558

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b) The weighted-average rate for the variable rate pollution control bonds was 0.18% at December 31, 2020 and 1.54% at December 31, 2019.

(c) The weighted-average interest rate was 2.12% at December 31, 2019. This term loan was repaid on May 26, 2020. See additional details below.

(d) The weighted-average interest rate was 2.20% at December 31, 2019. This term loan was repaid on June 19, 2020. See additional details below.

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Maturity Interest December 31,
Dates (a) Rates 2019 2018
APS

Pollution control bonds:

Variable 2029 (b) $ 35,975
$ 35,975
Fixed 2024 4.70% 115,150
115,150
Total pollution control bonds 151,125
151,125
Senior unsecured notes 2020-2049 2.20%-6.88% 4,875,000
4,575,000
Term loans
(c) 200,000
—
Unamortized discount (12,434 ) (12,638 )
Unamortized premium 7,423
7,736
Unamortized debt issuance cost (37,981 ) (31,787 )
Total APS long-term debt 5,183,133
4,689,436
Less current maturities
350,000
500,000
Total APS long-term debt less current maturities 4,833,133
4,189,436
Pinnacle West

Senior unsecured notes 2020 2.25% 300,000
300,000
Term loan 2020 (d) 150,000
150,000
Unamortized discount (57 ) (121 )
Unamortized debt issuance cost (518 ) (1,083 )
Total Pinnacle West long-term debt 449,425
448,796
Less current maturities 450,000
—
Total Pinnacle West long-term debt less current maturities (575 ) 448,796
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
$ 4,832,558
$ 4,638,232


~~(a)~~	~~This schedule does not reflect the timing of redemptions that may occur prior to maturities.~~


~~(b)~~	~~The weighted-average rate for the variable rate pollution control bonds was 1.54% at December 31, 2019 and 1.76% at December 31, 2018.~~


~~(c)~~	~~The weighted-average interest rate was 2.12% at December 31, 2019.~~


~~(d)~~	~~The weighted-average interest rate was 2.20% at December 31, 2019 and 3.02% at December 31, 2018.~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

Year
Consolidated
Pinnacle West

Consolidated
APS
2020 $ 800,000
$ 350,000
2021 —
—
2022 —
—
2023 —
—
2024 365,150
365,150
Thereafter 4,510,975
4,510,975
Total $ 5,676,125
$ 5,226,125


Year	Consolidated Pinnacle West		Consolidated APS
2021	$	0	$	0
2022	0		0
2023	0		0
2024	250,000		250,000
2025	800,000		300,000
Thereafter	5,315,975		5,315,975
Total	$	6,365,975	$	5,865,975

Debt Fair Value

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

As of
December 31, 2019 As of
December 31, 2018

Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Pinnacle West $ 449,425
$ 450,822
$ 448,796
$ 443,955
APS 5,183,133
5,743,570
4,689,436
4,789,608
Total $ 5,632,558
$ 6,194,392
$ 5,138,232
$ 5,233,563


	As of December 31, 2020				As of December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	496,321	$	509,050	$	449,425	$	450,822
APS	5,817,945		7,103,791		5,183,133		5,743,570
Total	$	6,314,266	$	7,612,841	$	5,632,558	$	6,194,392

Credit Facilities and Debt Issuances

~~APS~~Pinnacle West

On ~~February~~ ~~28, 2019, APS~~June 17, 2020, Pinnacle West issued ~~$300~~$500 million of ~~4.25%~~1.3% unsecured senior notes that mature ~~on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.~~

~~On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.~~

~~On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August~~June 15, ~~2029.~~ 2025. The net proceeds from the sale were used to repay ~~short-term indebtedness, consisting of commercial paper borrowings, and~~early its $150 million term loan facility set to ~~replenish cash used to fund capital expenditures.~~

~~On November 20, 2019, APS issued~~ ~~$300 million~~ ~~of 3.5% unsecured~~ ~~senior notes that~~ mature on December ~~1, 2049.~~ ~~The net proceeds from the sale were used~~21, 2020, to repay short-term indebtedness consisting of commercial paper ~~borrowings, to~~and replenish cash incurred or used to fund capital expenditures, ~~and~~ to redeem ~~on December~~prior to maturity our $300 million, 2.25% senior notes due November 30, ~~2019,~~ 2020, and for general corporate purposes.

~~$100 million~~ ~~of the~~ ~~$250 million aggregate principal amount of~~ ~~our~~ ~~2.2%~~ ~~Notes due January 15, 2020.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~APS

On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes.

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On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes ~~mentioned above.~~that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, ~~2019,~~2020, the ratio was approximately ~~52%~~54% for Pinnacle West and ~~47%~~49% for APS. Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On ~~November 27, 2018,~~December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved ~~an increase in~~ APS’s long-term debt authorization from ~~$5.1~~$5.9 billion to ~~$5.9~~$7.5 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. ~~See~~(See Note 6 for additional short-term debt provisions.)

8. Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement ~~Arrangement)~~Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. ~~See~~(See Note 1413 for further discussion of how fair values are determined.) Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00% (see weighted-average assumption table below). This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust. The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs (see Note 19). The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.

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A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and ~~therefore is~~are recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory ~~liability.~~liability (see Note 4).

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

Pension �� Other Benefits
2019 2018 2017 2019 2018 2017
Service cost-benefits earned during the period $ 49,902
$ 56,669
$ 54,858
$ 18,369
$ 21,100
$ 17,119
Interest cost on benefit obligation 136,843
124,689
129,756
29,894
28,147
29,959
Expected return on plan assets (171,884 ) (182,853 ) (174,271 ) (38,412 ) (42,082 ) (53,401 )
Amortization of:

Prior service cost (credit) —
—
81
(37,821 ) (37,842 ) (37,842 )
Net actuarial loss 42,584
32,082
47,900
—
—
5,118
Net periodic benefit cost (benefit) $ 57,445
$ 30,587
$ 58,324
$ (27,970 ) $ (30,677 ) $ (39,047 )
Portion of cost charged to expense $ 30,312
$ 10,120
$ 27,295
$ (19,859 ) $ (21,426 ) $ (18,274 )


	Pension Plans						Other Benefits Plans
	2020		2019		2018		2020		2019		2018
Service cost-benefits earned during the period	$	56,233	$	49,902	$	56,669	$	22,236	$	18,369	$	21,100
Interest cost on benefit obligation	118,567		136,843		124,689		25,857		29,894		28,147
Expected return on plan assets	(187,443)		(171,884)		(182,853)		(40,077)		(38,412)		(42,082)
Amortization of:
Prior service credit	0		0		0		(37,575)		(37,821)		(37,842)
Net actuarial loss	34,612		42,584		32,082		0		0		0
Net periodic benefit cost/(benefit)	$	21,969	$	57,445	$	30,587	$	(29,559)	$	(27,970)	$	(30,677)
Portion of cost/(benefit) charged to expense	$	3,386	$	30,312	$	10,120	$	(20,966)	$	(19,859)	$	(21,426)

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table shows the plans’ changes in the benefit obligations and funded status ~~for the years 2019 and 2018~~ (dollars in thousands):


	Pension Plans				Other Benefits Plans
	2020		2019		2020		2019
Change in Benefit Obligation
Benefit obligation at January 1	$	3,613,114	$	3,190,626	$	746,924	$	676,771
Service cost	56,233		49,902		22,236		18,369
Interest cost	118,567		136,843		25,857		29,894
Benefit payments	(191,704)		(177,882)		(31,511)		(32,486)
Actuarial (gain) loss	306,657		413,625		(139,472)		54,376

Benefit obligation at December 31	3,902,867		3,613,114		624,034		746,924
Change in Plan Assets
Fair value of plan assets at January 1	3,318,351		2,733,476		837,494		723,677
Actual return on plan assets	642,373		602,030		150,076		144,095
Employer contributions	100,000		150,000		0		0
Benefit payments	(174,180)		(167,155)		(26,405)		(30,278)

Fair value of plan assets at December 31	3,886,544		3,318,351		961,165		837,494
Funded Status at December 31	$	(16,323)	$	(294,763)	$	337,131	$	90,570

Pension Other Benefits
2019 2018 2019 2018
Change in Benefit Obligation

Benefit obligation at January 1 $ 3,190,626
$ 3,394,186
$ 676,771
$ 753,393
Service cost 49,902
56,669
18,369
21,100
Interest cost 136,843
124,689
29,894
28,147
Benefit payments (177,882 ) (184,161 ) (32,486 ) (31,540 )
Actuarial (gain) loss 413,625
(200,757 ) 54,376
(94,329 )
Benefit obligation at December 31 3,613,114
3,190,626
746,924
676,771
Change in Plan Assets

Fair value of plan assets at January 1 2,733,476
3,057,027
723,677
1,022,371
Actual return on plan assets 602,030
(201,078 ) 144,095
(40,354 )
Employer contributions 150,000
50,000
—
—
Benefit payments (167,155 ) (172,473 ) (30,278 ) (72,453 )
Transfer to active union medical account —
—
—
(185,887 )
Fair value of plan assets at December 31 3,318,351
2,733,476
837,494
723,677
Funded Status at December 31 $ (294,763 ) $ (457,150 ) $ 90,570
$ 46,906

The following table shows ~~the projected benefit obligation and the accumulated benefit obligation~~information for pension plans with an accumulated obligation in excess of plan assets ~~as of December 31, 2019 and 2018~~ (dollars in thousands):


	As of December 31,
	2020	2019
Accumulated benefit obligation	171,672	169,091
Fair value of plan assets	0	0

2019 2018
Projected benefit obligation $ 177,775
$ 3,190,626
Accumulated benefit obligation 169,091
3,038,774
Fair value of plan assets —
2,733,476

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The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated ~~benefits~~benefit obligation basis at December 31, 2020 and December 31, 2019, therefore the only pension plan with an accumulated ~~benefits~~benefit obligation in excess of plan assets in 2020 and 2019 is a non-qualified supplemental excess benefit retirement plan.

The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):


	As of December 31,
	2020	2019
Projected benefit obligation	182,184	3,613,114
Fair value of plan assets	0	3,318,351

The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2020 is a non-qualified supplemental excess benefit retirement plan.

The following table shows the amounts recognized on the Consolidated Balance Sheets ~~as of December 31, 2019 and 2018~~ (dollars in thousands):

Pension Other Benefits
2019 2018 2019 2018
Noncurrent asset $ —
$ —
$ 90,570
$ 46,906
Current liability (14,578 ) (13,980 ) —
—
Noncurrent liability (280,185 ) (443,170 ) —
—
Net amount recognized $ (294,763 ) $ (457,150 ) $ 90,570
$ 46,906


	Pension Plans				Other Benefits Plans
	2020		2019		2020		2019
Noncurrent asset	$	165,861	$	0	$	337,131	$	90,570
Current liability	(15,700)		(14,578)		0		0
Noncurrent liability	(166,484)		(280,185)		0		0
Net amount recognized	$	(16,323)	$	(294,763)	$	337,131	$	90,570

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table shows the details related to accumulated other comprehensive loss as of December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Pension Plans				Other Benefits Plans
	2020		2019		2020		2019
Net actuarial loss (gain)	$	552,301	$	735,186	$	(237,233)	$	12,238
Prior service credit	0		0		(152,337)		(189,912)
APS’s portion recorded as a regulatory (asset) liability	(469,953)		(660,223)		387,293		177,209
Income tax expense (benefit)	(20,364)		(18,546)		1,018		570
Accumulated other comprehensive loss (gain)	$	61,984	$	56,417	$	(1,259)	$	105

Pension Other Benefits
2019 2018 2019 2018
Net actuarial loss $ 735,186
$ 794,292
$ 12,238
$ 63,544
Prior service credit —
—
(189,912 ) (227,733 )
APS’s portion recorded as a regulatory (asset) liability (660,223 ) (733,351 ) 177,209
163,767
Income tax expense (benefit) (18,546 ) (15,083 ) 570
561
Accumulated other comprehensive loss $ 56,417
$ 45,858
$ 105
$ 139

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The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2020 (dollars in thousands):

Pension
Other
Benefits
Net actuarial loss $ 33,642
$ —
Prior service credit —
(37,575 )
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020 $ 33,642
$ (37,575 )

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:


	Benefit Obligations As of December 31,				Benefit Costs For the Years Ended December 31,
	2020		2019		2020		2019		2018
Discount rate – pension plans	2.53	%	3.30	%	3.30	%	4.34	%	3.65	%
Discount rate – other benefits plans	2.63	%	3.42	%	3.42	%	4.39	%	3.71	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on plan assets - pension plans	N/A		N/A		5.75	%	6.25	%	6.05	%
Expected long-term return on plan assets - other benefit plans	N/A		N/A		4.85	%	5.40	%	5.40	%
Initial healthcare cost trend rate (pre-65 participants)	6.50	%	7.00	%	7.00	%	7.00	%	7.00	%
Ultimate healthcare cost trend rate (pre-65 participants)	4.75	%	4.75	%	4.75	%	4.75	%	4.75	%
Number of years to ultimate trend rate (pre-65 participants)	5		6		5		7		8
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)	2.00	%	4.75	%	4.75	%	4.75	%	4.75	%

Interest crediting rate – cash balance pension plans	4.50	%	4.50	%	4.50	%	4.50	%	4.50	%

Benefit Obligations
As of December 31,

Benefit Costs
For the Years Ended December 31,
2019 2018 2019 2018 2017
Discount rate – pension 3.30 % 4.34 % 4.34 % 3.65 % 4.08 %
Discount rate – other benefits 3.42 % 4.39 % 4.39 % 3.71 % 4.17 %
Rate of compensation increase 4.00 % 4.00 % 4.00 % 4.00 % 4.00 %
Expected long-term return on plan assets - pension N/A
N/A
6.25 % 6.05 % 6.55 %
Expected long-term return on plan assets - other benefits N/A
N/A
5.40 % 5.40 % 6.05 %
Initial healthcare cost trend rate (pre-65 participants) 7.00 % 7.00 % 7.00 % 7.00 % 7.00 %
Initial healthcare cost trend rate (post-65 participants) 4.75 % 4.75 % 4.75 % 4.75 % 5.00 %
Ultimate healthcare cost trend rate 4.75 % 4.75 % 4.75 % 4.75 % 5.00 %
Number of years to ultimate trend rate (pre-65 participants) 6
7
7
8
4

(a)See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For ~~2020,~~2021, we are assuming a ~~5.75%~~5.30% long-term rate of return for pension assets and ~~5.00%~~5.05% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. ~~A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2019 amounts (dollars in thousands):~~

1% Increase 1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants $ 9,299
$ (3,827 )
Effect on service and interest cost components of net periodic other postretirement benefit costs 9,434
(7,257 )
Effect on the accumulated other postretirement benefit obligation 124,073
(97,710 )

Plan Assets

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other

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government agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, and other instruments.

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments may include investments in real estate, private equity and various other strategies. The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.

Based on the IPS, and given the pension ~~plan's~~plan’s funded status at year-end ~~2019,~~2020, the target and actual allocation for the pension plan at December 31, ~~2019~~2020 are as follows:


	Pension Plans
	Target Allocation		Actual Allocation
Long-term fixed income assets	72	%	68	%
Return-generating assets	28	%	32	%
Total	100	%	100	%

Pension
Target Allocation Actual Allocation
Long-term fixed income assets 62 % 63 %
Return-generating assets 38 % 37 %
Total 100 % 100 %

The permissible range is within +/~~- 3%~~-3% of the target allocation shown in the above table, and also considers the ~~plan's~~plan’s funded status. At December 31, 2020, the return-seeking assets were slightly outside the target allocation permissible range and were rebalanced to within the target range during January 2021.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:



Asset Class	Target Allocation
Equities in US and other developed markets	1817	%
Equities in emerging markets	6	%
Alternative investments	145	%
Total	3828	%

The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade.

As of December 31, ~~2019,~~2020, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, ~~2019:~~2020:



	Other Benefits Plans
	Actual Allocation
Long-term fixed income assets	6855	%
Return-generating assets	3245	%
Total	100	%

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See Note 1413 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.

Mutual funds, partnerships, and common and collective trusts are valued utilizing a Net Asset Value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The ~~trust's~~trust’s shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

NAV for trusts investing in real estate is derived from the appraised values of the ~~trust's~~trust’s underlying real estate assets. As of December 31, ~~2019,~~2020, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the ~~partnerships'~~partnerships’ underlying assets. The ~~plan's~~plan’s partnerships holdings relate to investments in high-yield fixed income ~~instruments and assets of privately held portfolio companies.~~instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, ~~2019,~~2020, approximately $38 million of these commitments have been funded.

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2020, by asset category, are as follows (dollars in thousands):


	Level 1		Level 2		Other (a)		Total
Pension Plan:
Cash and cash equivalents	$	9,911	$	—	$	—	$	9,911
Fixed income securities:
Corporate	—		1,684,782		—		1,684,782
U.S. Treasury	794,571		—		—		794,571
Other (b)	—		112,224		—		112,224
Common stock equities (c)	331,058		—		—		331,058
Mutual funds (d)	262,765		—		—		262,765
Common and collective trusts:
Equities	—		—		407,522		407,522
Real estate	—		—		191,595		191,595

Partnerships	—		—		22,420		22,420
Short-term investments and other (e)	—		0		69,696		69,696
Total	$	1,398,305	$	1,797,006	$	691,233	$	3,886,544
Other Benefits:
Cash and cash equivalents	$	1,909	$	—	$	—	$	1,909
Fixed income securities:
Corporate	—		221,488		—		221,488
U.S. Treasury	258,102		—		—		258,102
Other (b)	—		8,316		—		8,316
Common stock equities (c)	175,605		—		—		175,605
Mutual funds (d)	34,310		—		—		34,310
Common and collective trusts:
Equities	—		—		94,674		94,674
Real estate	—		—		19,778		19,778

Short-term investments and other (e)	142,995		0		3,988		146,983
Total	$	612,921	$	229,804	$	118,440	$	961,165

(a)These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.

(b)This category consists primarily of debt securities issued by municipalities.

(c)This category primarily consists of U.S. common stock equities.

(d)These funds invest in international common stock equities.

(e)This category includes plan receivables and payables.

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019, by asset category, are as follows (dollars in thousands):


	Level 1		Level 2		Other (a)		Total
Pension Plan:
Cash and cash equivalents	$	9,370	$	—	$	—	$	9,370
Fixed income securities:
Corporate	—		1,541,729		—		1,541,729
U.S. Treasury	406,112		—		—		406,112
Other (b)	—		92,240		—		92,240
Common stock equities (c)	250,829		—		—		250,829
Mutual funds (d)	185,928		—		—		185,928
Common and collective trusts:
Equities	—		—		392,403		392,403
Real estate	—		—		171,645		171,645
Fixed Income	—		—		98,065		98,065
Partnerships	—		—		103,796		103,796
Short-term investments and other (e)	—		—		66,234		66,234
Total	$	852,239	$	1,633,969	$	832,143	$	3,318,351
Other Benefits:
Cash and cash equivalents	$	2,184	$	—	$	—	$	2,184
Fixed income securities:
Corporate	—		202,640		—		202,640
U.S. Treasury	353,650		—		—		353,650
Other (b)	—		7,999		—		7,999
Common stock equities (c)	146,316		—		—		146,316
Mutual funds (d)	14,351		—		—		14,351
Common and collective trusts:
Equities	—		—		83,648		83,648
Real estate	—		—		19,806		19,806

Short-term investments and other (e)	2,881		0		4,019		6,900
Total	$	519,382	$	210,639	$	107,473	$	837,494

Level 1 Level 2 Other (a) Total
Pension Plan:

Cash and cash equivalents $ 9,370
$ —
$ —
$ 9,370
Fixed income securities:

Corporate —
1,541,729
—
1,541,729
U.S. Treasury 406,112
—
—
406,112
Other (b) —
92,240
—
92,240
Common stock equities (c) 250,829
—
—
250,829
Mutual funds (d) 185,928
—
—
185,928
Common and collective trusts:
   Equities —
—
392,403
392,403
   Real estate —
—
171,645
171,645
   Fixed Income —
—
98,065
98,065
Partnerships —
—
103,796
103,796
Short-term investments and other (e) —
—
66,234
66,234
Total $ 852,239
$ 1,633,969
$ 832,143
$ 3,318,351
Other Benefits:

Cash and cash equivalents $ 2,184
$ —
$ —
$ 2,184
Fixed income securities:

Corporate —
202,640
—
202,640
U.S. Treasury 353,650
—
—
353,650
Other (b) —
7,999
—
7,999
Common stock equities (c) 146,316
—
—
146,316
Mutual funds (d) 14,351
—
—
14,351
Common and collective trusts:

   Equities —
—
83,648
83,648
   Real estate —
—
19,806
19,806
Short-term investments and other (e) 2,881
—
4,019
6,900
Total $ 519,382
$ 210,639
$ 107,473
$ 837,494


~~(a)~~	(a)These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the ~~fair value hierarchy.~~


~~(b)~~	~~This category consists primarily of debt securities issued by municipalities.~~


~~(c)~~	~~This category primarily consists of U.S. common stock equities.~~


~~(d)~~	~~These funds invest in international common stock equities.~~


~~(e)~~	~~This category includes plan receivables and payables.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~The~~ fair value hierarchy.

(b)This category consists primarily of ~~Pinnacle West’s pension~~debt securities issued by municipalities.

(c)This category primarily consists of U.S. common stock equities.

(d)These funds invest in U.S. and international common stock equities.

(e)This category includes plan receivables and ~~other postretirement benefit plan assets at December 31, 2018, by asset category, are as follows (dollars in thousands):~~payables.

Level 1 Level 2 Other (a) Total
Pension Plan:

Cash and cash equivalents $ 451
$ —
$ —
$ 451
Fixed income securities:

Corporate —
1,237,744
—
1,237,744
U.S. Treasury 372,649
—
—
372,649
Other (b) —
78,902
—
78,902
Common stock equities (c) 196,661
—
—
196,661
Mutual funds (d) 120,976
—
—
120,976
Common and collective trusts:
   Equities —
—
272,926
272,926
   Real estate —
—
165,123
165,123
   Fixed Income —
—
86,483
86,483
Partnerships —
—
125,217
125,217
Short-term investments and other (e) —
—
76,344
76,344
Total $ 690,737
$ 1,316,646
$ 726,093
$ 2,733,476
Other Benefits:

Cash and cash equivalents $ 93
$ —
$ —
$ 93
Fixed income securities:

Corporate —
163,286
—
163,286
U.S. Treasury 318,017
—
—
318,017
Other (b) —
7,531
—
7,531
Common stock equities (c) 129,199
—
—
129,199
Mutual funds (d) 10,963
—
—
10,963
Common and collective trusts:
   Equities —
—
65,720
65,720
   Real estate —
—
19,054
19,054
Short-term investments and other (e) 3,633
—
6,181
9,814
Total $ 461,905
$ 170,817
$ 90,955
$ 723,677


~~(a)~~	~~These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.~~


~~(b)~~	~~This category consists primarily of debt securities issued by municipalities.~~


~~(c)~~	~~This category primarily consists of U.S. common stock equities.~~


~~(d)~~	~~These funds invest in U.S. and international common stock equities.~~


~~(e)~~	~~This category includes plan receivables and payables.~~

Contributions

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in ~~2018, and $100 million in 2017.~~2018. The minimum required contributions for the pension plan are 0 for the next three years. We expect to make voluntary contributions up to $100 million ~~per year during the 2020-2022 period.~~in 2021 and zero thereafter. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in ~~2019~~2020 and ~~2018. We made a contribution of approximately $1 million in 2017.~~2019. We do not expect to make any contributions over the next three years to

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our other postretirement benefit plans. The Company was

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets. ~~The Company was not reimbursed in 2017.~~

Estimated Future Benefit Payments

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):

Year Pension Other Benefits
2020 $ 199,395
$ 31,531
2021 201,597
32,777
2022 206,618
33,566
2023 213,208
34,415
2024 218,150
34,468
Years 2025-2029 1,111,171
174,607


Year	Pension Plans		Other Benefits Plans
2021	$	210,119	$	31,204
2022	209,593		31,731
2023	215,527		32,196
2024	220,241		31,914
2025	220,787		31,484
Years 2026-2030	1,116,848		153,536

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In ~~2019,~~2020, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $11 million for ~~2019,~~2020, $11 million for ~~2018,~~2019, and ~~$10~~$11 million for ~~2017.~~

2018.

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9. Leases

We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in ~~2020~~2021 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with 3 separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. ~~See~~(See Note 1918 for a discussion of VIEs.)

On ~~January~~June 1, ~~2019 we adopted new~~2020 APS had 2 separate purchased power lease ~~accounting guidance (see Note 3). We~~contracts that commenced. The lease terms end on September 30, 2025 and September 30, 2026, respectively. Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term. APS does not operate or maintain these leased assets. APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets APS has elected to combine both the ~~transition method that allows us to apply~~lease and non-lease payment components and accounts for the ~~new~~entire fixed payment as a lease guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existingobligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities.term extension options. In addition to ~~these balance sheet impacts,~~ the ~~adoption~~fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the ~~guidance resulted~~asset. The variable consideration is not included in ~~expanded~~the measurement of our lease ~~disclosures, which are included below.~~obligation.

The following table provides information related to our lease costs (dollars in thousands):


	Year Ended December 31, 2020						Year Ended December 31, 2019
	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total		Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
Operating lease cost	$	68,883	$	18,493	$	87,376	$	42,190	$	18,038	$	60,228
Variable lease cost	121,359		972		122,331		113,233		782		114,015
Short-term lease cost	0		3,804		3,804		0		4,385		4,385
Total lease cost	$	190,242	$	23,269	$	213,511	$	155,423	$	23,205	$	178,628

Year Ended
December 31, 2019
Purchased Power Lease Contracts Land, Property & Equipment Leases Total
Operating lease cost $ 42,190
$ 18,038
$ 60,228
Variable lease cost 113,233
782
114,015
Short-term lease cost —
4,385
4,385
Total lease cost $ 155,423
$ 23,205
$ 178,628

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements

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have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

~~Lease disclosures relating to 2018 and 2017 are presented under prior lease accounting guidance.~~ Lease expense recognized in the Consolidated Statements of Income was $18 million in 2018, ~~and $18 million in 2017, these amounts do~~this amount does not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in ~~2018 and $60 million in 2017.~~2018. In addition, contingent rents for purchased power lease contracts was $109 million in ~~2018 and $100 million in 2017.~~2018. These purchased power lease costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):


	December 31, 2019							December 31, 2020
Year	Purchased Power Lease Contracts (a)		Land, Property & Equipment Leases		Total		Year	Purchased Power Lease Contracts		Land, Property & Equipment Leases		Total
2020	$	—	$	14,698	$	14,698
2021	—		11,963		11,963		2021	$	66,658	$	14,455	$	81,113
2022	—		8,331		8,331		2022	68,325		10,849		79,174
2023	—		6,326		6,326		2023	70,033		8,503		78,536
2024	—		4,141		4,141		2024	71,784		6,104		77,888
2025							2025	73,578		4,400		77,978
Thereafter	—		38,697		38,697		Thereafter	36,760		37,314		74,074
Total lease commitments	—		84,156		84,156		Total lease commitments	387,138		81,625		468,763
Less imputed interest	—		19,571		19,571		Less imputed interest	14,375		18,267		32,642
Total lease liabilities	$	—	$	64,585	$	64,585	Total lease liabilities	$	372,763	$	63,358	$	436,121

(a) As of December 31, 2019, we had no operating lease liabilities relating to purchased power lease contracts. See discussion below regarding executed contracts with commencement dates beginning in June 2020.

We recognize lease assets and liabilities upon lease commencement. At December 31, ~~2019,~~2020, we have ~~additional~~certain purchased power lease ~~arrangements~~contracts, that have been executed but have not yet commenced. ~~These arrangements primarily relate to~~In January 2021, we also executed additional purchased power lease ~~contracts.~~contracts relating to energy storage. These ~~leases~~arrangements have commencement dates beginning in ~~June 2020~~May 2021 with terms ending through ~~October 2027.~~December 2042. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate ~~$705~~$650 million over the term of the arrangements.

~~The following table provides information related to estimated future minimum operating lease payments (dollars in thousands):~~

December 31, 2018
Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total
2019 $ 54,499
$ 13,747
$ 68,246
2020 —
12,428
12,428
2021 —
9,478
9,478
2022 —
6,513
6,513
2023 —
5,359
5,359
Thereafter —
42,236
42,236
Total future lease commitments $ 54,499
$ 89,761
$ 144,260

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The following tables provide other additional information related to operating lease ~~liabilities:~~liabilities (dollars in thousands):


	Year Ended December 31, 2020		Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:	$	75,097	$	69,075
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	441,653		11,262



	~~December 31, 2019~~
~~Weighted average remaining lease term~~	~~13 years~~
~~Weighted average discount rate (a)~~	~~3.71~~	%


	December 31, 2020		December 31, 2019
Weighted average remaining lease term	6 years		13 years
Weighted average discount rate (a)	1.69	%	3.71	%

(a)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.

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Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands): $ 69,075

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, ~~2019~~2020 (dollars in thousands):


	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,911,339	$	1,108,883	$	26,623
Palo Verde Unit 2 (a)	16.8	%		649,035		379,305		7,268
Palo Verde Common	28.0	%	(b)	774,054		320,107		41,607
Palo Verde Sale Leaseback			(a)	351,050		253,014		0
Four Corners Generating Station	63.0	%		1,621,418		581,436		35,028
Cholla common facilities (c)	50.5	%		193,807		109,447		1,206
Transmission facilities:
ANPP 500kV System	33.5	%	(b)	131,991		52,626		3,859
Navajo Southern System	26.0	%	(b)	89,113		33,536		1,215
Palo Verde — Yuma 500kV System	25.3	%	(b)	23,247		6,681		433
Four Corners Switchyards	61.8	%	(b)	69,441		17,009		3,145
Phoenix — Mead System	17.1	%	(b)	39,437		19,072		73
Palo Verde — Rudd 500kV System	50.0	%		93,123		28,206		1,921
Morgan — Pinnacle Peak System	64.6	%	(b)	117,497		20,754		912
Round Valley System	50.0	%		531		174		13
Palo Verde — Morgan System	88.9	%	(b)	257,220		20,943		530
Hassayampa — North Gila System	80.0	%		148,067		16,080		0
Cholla 500kV Switchyard	85.7	%		7,896		1,850		940
Saguaro 500kV Switchyard	60.0	%		21,669		13,229		2
Kyrene — Knox System	50.0	%		578		323		—

Percent
Owned

Plant in
Service

Accumulated
Depreciation

Construction
Work in
Progress

Generating facilities:

Palo Verde Units 1 and 3 29.1 %
$ 1,877,748
$ 1,102,609
$ 22,071

Palo Verde Unit 2 (a) 16.8 %
634,545
377,722
11,831

Palo Verde Common 28.0 % (b) 746,653
290,084
46,570

Palo Verde Sale Leaseback
(a) 351,050
249,144
—

Four Corners Generating Station 63.0 %
1,520,171
559,272
44,842

Cholla common facilities (c) 50.5 %
184,608
95,720
1,323

Transmission facilities:

ANPP 500kV System 33.5 % (b) 133,396
51,248
2,723

Navajo Southern System 26.7 % (b) 89,672
31,985
194

Palo Verde — Yuma 500kV System 19.0 % (b) 15,274
6,486
4,886

Four Corners Switchyards 63.0 % (b) 69,994
16,674
2,395

Phoenix — Mead System 17.1 % (b) 39,355
18,570
53

Palo Verde — Rudd 500kV System 50.0 %
93,112
26,719
317

Morgan — Pinnacle Peak System 64.6 % (b) 117,752
18,822
—

Round Valley System 50.0 %
515
164
—

Palo Verde — Morgan System 88.9 % (b) 238,689
13,146
—

Hassayampa — North Gila System 80.0 %
143,422
12,676
—

Cholla 500kV Switchyard 85.7 %
7,651
1,597
535

Saguaro 500kV Switchyard 60.0 %
20,425
12,949
—

Kyrene — Knox System 50.0 %
578
315
—

(a)See Note 18.


~~(a)~~	~~See Note 19.~~


~~(b)~~	~~Weighted-average of interests.~~


~~(c)~~	(b)Weighted-average of interests. (c)PacifiCorp owns Cholla Unit 4 (see ~~Note 4 for additional information) and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.~~

~~See "Navajo Plant" in~~ Note 4 for ~~more details.~~additional information) and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. Cholla Unit 4 was retired on December 24, 2020.

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11. Commitments and Contingencies

Palo Verde Generating Station

Spent Nuclear Fuel and Waste Disposal

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~~United States Department of Energy (“DOE”) in the United States Court of Federal Claims ("(“Court of Federal ~~Claims"~~Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("(“Standard ~~Contract"~~Contract”) for failing to accept Palo ~~Verde's~~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 Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to 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, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.

APS has submitted 56 claims pursuant to the terms of the August 18, 2014 settlement agreement, for ~~five~~6 separate time periods during July 1, 2011 through June 30, ~~2018.~~2019. The DOE has approved and paid ~~$84.3~~$99.7 million for these claims (APS’s share is ~~$24.5~~$29.0 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On ~~October 31, 2019,~~November 2, 2020, APS filed its ~~next~~7th claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of ~~$16~~$12.2 million (APS’s share is ~~$4.7 million). On February 11, 2020, the DOE approved a payment of $15.4 million (APS’s share is $4.5~~$3.6 million).

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("(“Price-Anderson ~~Act"~~Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately ~~$13.9~~$13.8 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ~~("ANI"~~(“ANI”). The remaining balance of approximately ~~$13.5~~$13.3 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the ~~three~~3 Palo Verde units, APS’s maximum retrospective premium per incident for all 3 units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the 3 units. The property damage,

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decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ~~("NEIL"~~(“NEIL”). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

policies totals approximately ~~$25.5~~$25.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately ~~$73.4~~$75.1 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between ~~2020~~2021 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately ~~$590 million in 2020; $613~~$772 million in 2021; ~~$624~~$671 million in 2022; ~~$616~~$632 million in 2023; ~~$581~~$592 million in 2024; $564 million in 2025; and ~~$5.5~~$5.4 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts include estimated commitments relating to purchased power lease contracts (see Note 9).

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031.

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):

Years Ended December 31,
2020 2021 2022 2023 2024 Thereafter
Coal take-or-pay commitments (a) $ 185,347
$ 186,554
$ 187,400
$ 189,120
$ 193,192
$ 1,240,964


	Years Ended December 31,
	2021		2022		2023		2024		2025		Thereafter
Coal take-or-pay commitments (a)	$	182,569	$	183,604	$	184,540	$	186,804	$	177,114	$	1,024,854


~~(a)~~	~~Total take-or-pay commitments are approximately $2.2 billion. The total net present value of these commitments is approximately $1.6 billion.~~

(a)Total take-or-pay commitments are approximately $1.9 billion. The total net present value of these commitments is approximately $1.5 billion.

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):

Year Ended December 31,
2019 2018 2017
Total purchases $ 204,888
$ 206,093
$ 165,220


	Year Ended December 31,
	2020		2019		2018
Total purchases	$	189,817	$	204,888	$	206,093

Renewable Energy Credits

APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately ~~$36 million in 2020;~~ $35 million in 2021; $31 million in 2022; $30 million in 2023; $28 million in 2024; $25 million in 2025; and ~~$133~~$105 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

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Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $170 million at December 31, 2020 and $166 million at December 31, ~~2019 and $213 million at December 31, 2018.~~2019. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: ~~$17 million in 2020;~~ $16 million in 2021; $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; and ~~$88~~$69 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

The Comprehensive Environmental Response Compensation and Liability Act ~~("CERCLA"~~(“Superfund” or ~~"Superfund"~~“CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ~~("PRPs"~~(“PRPs”). PRPs may be strictly, and often are 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"~~(“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("(“RI/~~FS"~~FS”). 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 induring the ~~spring~~first or ~~summer~~second quarter of ~~2020.~~ 2021.We estimate that our costs related to this investigation and study will be approximately $2$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.

On August 6, 2013, the Roosevelt Irrigation District ~~("RID"~~(“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. As part of a 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. APS responded to ADEQ on May 4, 2015. On December 16, 2016, 2 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

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vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase ~~APS's~~APS’s exposure or risk related to these matters.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving ~~RID's~~RID’s CERCLA claims concerning both past and future cost recovery. ~~APS's~~APS’s share of this settlement was immaterial. In addition, the 2 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 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; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Arizona Attorney General Matter

APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.

Environmental Matters

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.

Regional Haze Rules. APS has received the final rulemaking imposing ~~new~~ pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, ~~APS's~~APS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred. 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~~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~~“Four Corners -— 4CA ~~Matter"~~Matter” below for a discussion of the NTEC purchase. The cost of the pollution controls related to

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the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Cholla. ~~APS believed that EPA’s original 2012~~In early 2017, EPA approved a final rule ~~establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving~~containing a revision to Arizona’s State Implementation Plan ~~("SIP"~~(“SIP”) ~~and promulgating a FIP~~for Cholla that ~~was inconsistent~~implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.In conjunction with the ~~state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close~~closure of Cholla Unit 2 ~~and cease burning~~in 2015, APS has committed to ceasing coal atcombustion within Units 1 and 3 by April 2025.PacifiCorp retired Cholla Unit 4 at the ~~mid-2020s.~~end of 2020. (See ~~"Cholla"~~“Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.asset).

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ~~("RCRA"~~(“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment ~~that is contaminating groundwater above a regulated constituent’s groundwater protection standard~~ to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed ~~"forced closure"~~“forced closure” or ~~"closure~~“closure for ~~cause"~~cause” of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

•Based on an August 21, 2018 D.C. 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 ~~November 4, 2019,~~July 29, 2020, EPA ~~proposed that all~~took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface ~~impoundments, regardless~~impoundments; such disposal units must close as soon as technically feasible, but no later than April 22, 2021.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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 ~~$22~~$27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately ~~$15~~$16 million. The Navajo Plant ~~currently disposes~~disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, ~~APS's~~APS’s share of incremental costs iswas approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

Clean Power Plan/Affordable Clean Energy Regulations. 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 ~~those~~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.~~

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EPA to develop new existing power ~~plants, specifically coal-fired EGUs. In contrast~~plant carbon regulations consistent with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon applicationcourt’s ruling. That ruling endorsed an expansive view of the ~~ACE rule’s heat-rate improvement emission guidelines.~~federal Clean Air Act consistent with EPA’s 2015 CPP. While ~~corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal,~~ the ~~finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs~~Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the ~~near future.~~

WeClean Air Act, we cannot at this time predict the outcome of ~~EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits~~pending EPA rulemaking proceedings in ~~the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition,~~response to the ~~extent that the~~court’s recent ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.decision.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

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, 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 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.

~~Federal Agency Environmental Lawsuit Related to Four Corners~~

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. ~~The Ninth Circuit denied this petition for rehearing on December 11, 2019.~~

Four Corners National Pollutant Discharge Elimination System ~~("NPDES"~~(“NPDES”) Permit

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ~~("EAB"~~(“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.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. ~~This permit is now subject to a petition for review before the EPA Environmental Appeals Board, based~~Based upon a November 1, 2019 filing by several environmental ~~groups.~~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.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. We cannot predict the outcome of ~~this review~~these appeal proceedings and, if such appeal is successful, whether ~~the review~~that outcome will have a material impact on our financial position, results of operations, or cash flows.

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Four Corners

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC ~~had the option to purchase the~~purchased this 7% interest o~~and ultimately purchased the interest on~~n July 3, 2018 from 4CA. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of December 31, 2020, the note has a remaining balance of $27 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.

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~~NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle ~~West's~~West’s guarantee is secured by a portion of ~~APS's~~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) iswas 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.~~obligations of which the prepayment has been fully utilized as of June 2020.

Financial Assurances

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of December 31, ~~2019,~~2020, standby letters of credit totaled ~~$1.7~~$5.2 million and will expire in ~~2020.~~2021. As of December 31, ~~2019,~~2020, surety bonds expiring through ~~2020~~2022 totaled ~~$14~~$16 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

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Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, ~~2019.~~2020. In connection with the sale of ~~4CA's~~4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See ~~"Four~~“Four Corners -— 4CA ~~Matter"~~Matter” above for information related to this guarantee.) Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West ~~reduce~~are reduced as payments are made under the respective ~~guaranteed~~guarantee agreements. The Equity Contribution Guarantees ~~are currently anticipated to be terminated upon completion~~remaining as of ~~construction of the respective projects, which is anticipated to occur prior to~~ December 31, 2020 are immaterial in amount (approximately $3 million) and the PTC Guarantees (approximately ~~$40~~$39 million as of December 31, ~~2019)~~2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.

12. Asset Retirement Obligations

In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the closure of ponds and facilities, and at Four Corners and the Navajo Plant relating to corrective action and water monitoring costs, which resulted in an increase to the ARO of $6 million. Also in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the ARO of $13 million.

In 2019, APS received updated decommissioning estimates for the Navajo Plant closure in December 2019, which resulted in a decrease to the ARO in the amount of $8 million (see Note 4 for additional information). In addition, APS received a new decommissioning study for Palo Verde. This resulted in a decrease to the ARO in the amount of $89 million, a decrease in plant in service of $80 million and a reduction in the regulatory liability of $9 million.

In 2018, APS recognized an ARO for the removal of hazardous waste containing solar panels at all of our utility scale solar plants, which resulted in an increase to the ARO in the amount of $14 million. In addition, due to the sale of 4CA assets to NTEC in 2018 (see Note 11 for more information on 4CA matters) there was a decrease to the ARO of $9 million. APS recognized an ARO of $7 million for rooftop solar removals in accordance with the obligations included in the customer contracts, which requires APS to remove the panels at the end of the contract life and includes the costs for the disposal of hazardous materials in accordance with environmental regulations. Finally, APS has other ARO adjustments resulting in a net decrease of $1 million.

The following table shows the change in our asset retirement obligations for ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):

2019 2018
Asset retirement obligations at the beginning of year $ 726,545
$ 679,529
Changes attributable to:

Accretion expense 39,726
36,876
Settlements (12,591 ) (9,726 )
Estimated cash flow revisions (96,462 ) 2,002
Newly incurred or acquired obligations —
17,864
Asset retirement obligations at the end of year $ 657,218
$ 726,545


	2020		2019
Asset retirement obligations at the beginning of year	$	657,218	$	726,545
Changes attributable to:
Accretion expense	38,652		39,726
Settlements	(9,710)		(12,591)

Estimated cash flow revisions	18,923		(96,462)
Asset retirement obligations at the end of year	$	705,083	$	657,218

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4.

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~~13. Selected Quarterly Financial Data (Unaudited)~~

Consolidated quarterly financial information for 2019 and 2018 is provided in the tables below (dollars in thousands, except per share amounts). Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

2019 Quarter Ended 2019
March 31, June 30, September 30, December 31, Total
Operating revenues $ 740,530
$ 869,501
$ 1,190,787
$ 670,391
$ 3,471,209
Operations and maintenance 245,634
227,543
238,582
229,857
941,616
Operating income 60,084
196,589
403,290
11,997
671,960
Income taxes 2,418
17,080
53,266
(88,537 ) (15,773 )
Net income 22,791
149,019
317,149
68,854
557,813
Net income attributable to common shareholders 17,918
144,145
312,276
63,981
538,320

Earnings Per Share:

Net income attributable to common shareholders — Basic $ 0.16
$ 1.28
$ 2.78
$ 0.57
$ 4.79
Net income attributable to common shareholders — Diluted 0.16
1.28
2.77
0.57
4.77

2018 Quarter Ended 2018
March 31, June 30, September 30, December 31, Total
Operating revenues $ 692,714
$ 974,123
$ 1,268,034
$ 756,376
$ 3,691,247
Operations and maintenance 265,682
268,397
246,545
256,120
1,036,744
Operating income 31,334
242,162
433,307
66,884
773,687
Income taxes (1,265 ) 44,039
84,333
6,795
133,902
Net income 8,094
171,612
319,885
30,949
530,540
Net income attributable to common shareholders 3,221
166,738
315,012
26,076
511,047

Earnings Per Share:

Net income attributable to common shareholders — Basic $ 0.03
$ 1.49
$ 2.81
$ 0.23
$ 4.56
Net income attributable to common shareholders — Diluted 0.03
1.48
2.80
0.23
4.54

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~Selected Quarterly Financial Data (Unaudited) - APS~~

~~APS's quarterly financial information for 2019 and 2018 is as follows (dollars in thousands):~~

2019 Quarter Ended 2019
March 31, June 30, September 30, December 31, Total
Operating revenues $ 740,530
$ 869,501
$ 1,190,787
$ 670,391
$ 3,471,209
Operations and maintenance 240,375
224,143
235,440
226,758
926,716
Operating income 65,377
200,018
406,465
15,124
686,984
Net income attributable to common shareholder 28,276
150,176
318,870
67,949
565,271

2018 Quarter Ended 2018
March 31, June 30, September 30, December 31, Total
Operating revenues $ 692,006
$ 971,963
$ 1,267,997
$ 756,376
$ 3,688,342
Operations and maintenance 254,601
251,999
226,346
236,281
969,227
Operating income 37,878
251,590
453,547
86,753
829,768
Net income attributable to common shareholder 9,599
177,825
338,366
44,475
570,265

~~14.~~13. Fair Value Measurements

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 — ~~Unadjusted~~Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity,

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning ~~trust~~trusts and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. ~~See~~(See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans.)

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Cash Equivalents

Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Derivative Instruments

Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. ~~Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization.

Investments Held in Nuclear Decommissioning ~~Trust~~Trusts and Other Special Use Funds

The nuclear decommissioning ~~trust~~trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical ~~trust. See~~account. (See Note 2019 for additional discussion about our investment accounts.)

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow ~~agent's~~agent’s internal operating controls and valuation processes.

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Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The ~~nuclear decommissioning trust's~~Nuclear Decommissioning Trust’s equity security investments are held indirectly through commingled funds. The commingled funds are valued using the ~~funds'~~funds’ NAV as a practical expedient. The ~~funds'~~funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled ~~funds'~~funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The ~~nuclear decommissioning trust~~Nuclear Decommissioning Trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices.

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Fair Value Tables

The following table presents the fair value at December 31, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
Assets

Risk management activities — derivative instruments:
Commodity contracts	$	0	$	9,016	$	4	$	(4,271)	(a)	$	4,749
Nuclear decommissioning trust:
Equity securities	29,796		0		0		(17,828)		(b)	11,968
U.S. commingled equity funds	0		0		0		610,055		(c)	610,055
U.S. Treasury debt	164,514		0		0		—			164,514
Corporate debt	0		149,509		0		—			149,509
Mortgage-backed securities	0		99,623		0		—			99,623
Municipal bonds	0		89,705		0		—			89,705
Other fixed income	0		13,061		0		—			13,061
Subtotal nuclear decommissioning trust	194,310		351,898		0		592,227			1,138,435

Other special use funds:

Equity securities	37,337		0		0		504		(b)	37,841
U.S. Treasury debt	203,220		0		0		—			203,220
Municipal bonds	0		13,448		0		—			13,448
Subtotal other special use funds	240,557		13,448		0		504			254,509

Total assets	$	434,867	$	374,362	$	4	$	588,460		$	1,397,693
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	0	$	(20,498)	$	(1,107)	$	2,986	(a)	$	(18,619)

(a)Represents counterparty netting, margin, and collateral (see Note 16).

(b)Represents net pending securities sales and purchases.

(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Other			Total
Assets

Risk management activities — derivative instruments:
Commodity contracts	$	0	$	551	$	33	$	(69)	(a)	$	515
Nuclear decommissioning trust:
Equity securities	10,872		0		0		2,401		(b)	13,273
U.S. commingled equity funds	0		0		0		518,844		(c)	518,844
U.S. Treasury debt	160,607		0		0		—			160,607
Corporate debt	0		115,869		0		—			115,869
Mortgage-backed securities	0		118,795		0		—			118,795
Municipal bonds	0		73,040		0		—			73,040
Other fixed income	0		10,347		0		—			10,347
Subtotal nuclear decommissioning trust	171,479		318,051		0		521,245			1,010,775

Other special use funds:
Equity securities	7,142		0		0		474		(b)	7,616
U.S. Treasury debt	232,848		0		0		—			232,848
Municipal bonds	0		4,631		0		—			4,631
Subtotal other special use funds	239,990		4,631		0		474			245,095

Total assets	$	411,469	$	323,233	$	33	$	521,650		$	1,256,385
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	0	$	(67,992)	$	(3,429)	$	(711)	(a)	$	(72,132)

Level 1
Level 2
Level 3
Other

Total
Assets

Risk management activities — derivative instruments:

Commodity contracts $ —

$ 551

$ 33

$ (69 )
(a)
$ 515
Nuclear decommissioning trust:

Equity securities 10,872

—

—

2,401

(b)
13,273
U.S. commingled equity funds —

—

—

518,844

(c)
518,844
U.S. Treasury debt 160,607

—

—

—

160,607
Corporate debt —

115,869

—

—

115,869
Mortgage-backed securities —

118,795

—

—

118,795
Municipal bonds —

73,040

—

—

73,040
Other fixed income —

10,347

—

—

10,347
Subtotal nuclear decommissioning trust 171,479

318,051

—

521,245

1,010,775

Other special use funds:

Equity securities 7,142

—

—

474

(b)
7,616
U.S. Treasury debt 232,848

—

—

—

232,848
Municipal bonds —

4,631

—

—

4,631
Subtotal other special use funds 239,990

4,631

—

474

245,095

Total assets $ 411,469

$ 323,233

$ 33

$ 521,650

$ 1,256,385
Liabilities

Risk management activities — derivative instruments:

Commodity contracts $ —

$ (67,992 )
$ (3,429 )
$ (711 )
(a)
$ (72,132 )
(a)Represents counterparty netting, margin, and collateral (see Note 16).

(b)Represents net pending securities sales and purchases.


~~(a)~~	~~Represents counterparty netting, margin, and collateral. See Note 17.~~


~~(b)~~	~~Represents net pending securities sales and purchases.~~


~~(c)~~	(c)Valued using NAV as a practical expedient and, therefore, are not classified in ~~the fair value hierarchy.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~The following table presents~~ the fair value ~~at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):~~hierarchy.

Level 1
Level 2
Level 3
Other

Total
Assets

Cash equivalents $ 1,200

$ —

$ —

$ —

$ 1,200
Risk management activities — derivative instruments:

Commodity contracts —

3,140

2

(2,029 )
(a)
1,113
Nuclear decommissioning trust:

Equity securities 5,203

—

—

2,148

(b)
7,351
U.S. commingled equity funds —

—

—

396,805

(c)
396,805
U.S. Treasury debt 148,173

—

—

—

148,173
Corporate debt —

96,656

—

—

96,656
Mortgage-backed securities —

113,115

—

—

113,115
Municipal bonds —

79,073

—

—

79,073
Other fixed income —

9,961

—

—

9,961
Subtotal nuclear decommissioning trust 153,376

298,805

—

398,953

851,134

Other special use funds:

Equity securities 45,130

—

—

593

(b)
45,723
U.S. Treasury debt 173,310

—

—

—

173,310
Municipal bonds —

17,068

—

—

17,068
Subtotal other special use funds 218,440

17,068

—

593

236,101

Total assets $ 373,016

$ 319,013

$ 2

$ 397,517

$ 1,089,548
Liabilities

Risk management activities — derivative instruments:

Commodity contracts $ —

$ (52,696 )
$ (8,216 )
$ 875

(a)
$ (60,037 )


~~(a)~~	~~Represents counterparty netting, margin, and collateral. See Note 17.~~


~~(b)~~	~~Represents net pending securities sales and purchases.~~


~~(c)~~	~~Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.~~

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the ~~quote.~~quote, or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

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Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

~~The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2019 and December 31, 2018:~~

December 31, 2019
Fair Value (thousands) Valuation Technique Significant Unobservable Input Range Weighted-Average
Commodity Contracts Assets Liabilities
Electricity:

Forward Contracts (a) $ 33
$ 819
Discounted cash flows Electricity forward price (per MWh) $22.18 - $22.18 $ 22.18
Natural Gas:

Forward Contracts (a) —
2,610
Discounted cash flows Natural gas forward price (per MMBtu) $2.33 -$ 2.78 $ 2.49
Total $ 33
$ 3,429


~~(a)~~	~~Includes swaps and physical and financial contracts.~~

December 31, 2018
Fair Value (thousands) Valuation Technique Significant Unobservable Input Range Weighted-Average
Commodity Contracts Assets Liabilities
Electricity:

Forward Contracts (a) $ —
$ 2,456
Discounted cash flows Electricity forward price (per MWh) $17.88 - $37.03 $ 26.10
Natural Gas:

Forward Contracts (a) 2
5,760
Discounted cash flows Natural gas forward price (per MMBtu) $1.79 - $2.92 $ 2.48
Total $ 2
$ 8,216


~~(a)~~	~~Includes swaps and physical and financial contracts.~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2019 and 2018 (dollars in thousands):

Year Ended
December 31,
Commodity Contracts 2019 2018
Net derivative balance at beginning of period $ (8,214 ) $ (18,256 )
Total net gains (losses) realized/unrealized:

Included in earnings —
—
Included in OCI —
—
Deferred as a regulatory asset or liability (13,457 ) (1,130 )
Settlements 12,250
(787 )
Transfers into Level 3 from Level 2 (6,512 ) (12,830 )
Transfers from Level 3 into Level 2 12,537
24,789
Net derivative balance at end of period $ (3,396 ) $ (8,214 )
Net unrealized gains included in earnings related to instruments still held at end of period $ —
$ —

~~Transfers~~ ~~between levels in the fair value hierarchy shown in the table above~~ reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had 0 significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. ~~See~~(See Note 7 for our long-term debt fair values.) The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of ~~$44.3~~$27.1 million as of December 31, ~~2019,~~2020, as presented on the Consolidated Balance Sheets. The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy. ~~See~~(See Note 11 for more information on 4CA matters.)

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~~15.~~14. Earnings Per Share

The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share ~~for continuing operations attributable to common shareholders for the years ended December 31, 2019, 2018 and 2017~~ (in thousands, except per share amounts):


	2020		2019		2018
Net income attributable to common shareholders	$	550,559	$	538,320	$	511,047
Weighted average common shares outstanding — basic	112,666		112,443		112,129
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	276		315		421
Weighted average common shares outstanding — diluted	112,942		112,758		112,550
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders — basic	$	4.89	$	4.79	$	4.56
Net income attributable to common shareholders — diluted	$	4.87	$	4.77	$	4.54

2019 2018 2017
Net income attributable to common shareholders $ 538,320
$ 511,047
$ 488,456
Weighted average common shares outstanding — basic 112,443
112,129
111,839
Net effect of dilutive securities:

Contingently issuable performance shares and restricted stock units 315
421
528
Weighted average common shares outstanding — diluted 112,758
112,550
112,367
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic $ 4.79
$ 4.56
$ 4.37
Net income attributable to common shareholders - diluted $ 4.77
$ 4.54
$ 4.35

~~16.~~15. Stock-Based Compensation

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, ~~2019, 1.6~~2020, 1.5 million common shares were available for issuance under the 2012 Plan. During 2020, 2019, ~~2018,~~ and ~~2017,~~2018, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $18 million in 2020, $18 million in 2019, and $20 million in ~~2018, and $21 million in 2017.~~2018. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $4 million in 2020, $7 million in 2019, and $7 million in ~~2018, and $15 million in 2017.~~2018.

As of December 31, ~~2019,~~2020, there were approximately $9 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $22 million in 2020, $21 million in 2019 and $24 million in ~~2018 and $22 million in 2017.~~2018.

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The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2020, 2019 ~~2018~~ and ~~2017:~~2018:


	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2020		2019		2018		2020		2019		2018
Units granted	118,403		109,106		132,997		122,830		142,874		171,708
Weighted-average grant date fair value	$	71.70	$	89.15	$	77.51	$	104.74	$	92.16	$	76.56

Restricted Stock Units, Stock Grants, and Stock Units (a) Performance Shares (b)
2019 2018 2017 2019 2018 2017
Units granted 109,106
132,997
161,963
142,874
171,708
147,706
Weighted-average grant date fair value $ 89.15
$ 77.51
$ 72.60
$ 92.16
$ 76.56
$ 78.99
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.


~~(a)~~	~~Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017.~~


~~(b)~~	~~Reflects the target payout level.~~

(b)Reflects the target payout level.

The following table is a summary of the status of non-vested awards as of December 31, ~~2019~~2020 and changes during the year:


											Restricted Stock Units, Stock Grants, and Stock Units				Performance Shares
	Restricted Stock Units, Stock Grants, and Stock Units					Performance Shares					Shares		Weighted-Average Grant Date Fair Value		Shares (b)	Weighted-Average Grant Date Fair Value
	Shares			Weighted-Average Grant Date Fair Value		Shares (b)		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2019	270,991			$	74.39	312,384		$	77.67
Nonvested at January 1, 2020										Nonvested at January 1, 2020	242,612		$	81.38	306,970	$	83.65
Granted	109,106			89.15		142,874		92.16		Granted	118,403		71.70		122,830	104.74
Vested	(132,102	)		73.48		(139,214	)	78.99		Vested	(136,893)		73.80		(161,906)	76.53
Forfeited (c)	(5,383	)		80.10		(9,074	)	81.03		Forfeited (c)	(3,565)		82.61		(7,890)	85.06
Nonvested at December 31, 2019	242,612		(a)	81.38		306,970		83.65
Vested Awards Outstanding at December 31, 2019	67,148					139,214
Nonvested at December 31, 2020										Nonvested at December 31, 2020	220,557	(a)	77.93		260,004	98.28
Vested Awards Outstanding at December 31, 2020										Vested Awards Outstanding at December 31, 2020	82,921		0		161,906	0


~~(a)~~	~~Includes 141,621 of awards that will be cash settled.~~


~~(b)~~	~~The nonvested performance shares are reflected at target payout level.~~


~~(c)~~	~~We account for forfeitures as they occur.~~

(a)Includes 126,996 of awards that will be cash settled.

(b)The nonvested performance shares are reflected at target payout level.

(c)We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $5$6 million, $4$5 million and $4 million in 2020, 2019 ~~2018~~ and ~~2017,~~2018, respectively. This includes cash used to settle restricted stock units of $5$4 million, $5 million and $4$5 million in 2020, 2019 ~~2018~~ and ~~2017,~~2018, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the ~~employee's~~employee’s retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a

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dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West. This award vested on December 31, 2016, because he remained employed with the Company through that date. The Board did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the ~~Company's~~Company’s closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, cash, or 50% in cash and 50% in stock.

Performance Share Awards

Performance share awards are granted to officers and key employees. The awards contain 2 separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle ~~West's~~West’s total shareholder return ~~("TSR"~~(“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.

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~~17.~~16. Derivative Accounting

Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and ~~fuels.~~natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. ~~See~~(See Note 1413 for a discussion of fair value measurements.) Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

~~As of December 31, 2019 and 2018, we had~~The following table shows the ~~following~~ outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

Quantity

Commodity

Unit of Measure

December 31, 2019

December 31, 2018

Commodity

Unit of Measure

December 31, 2020

December 31, 2019

Power

GWh

193

250

Power

GWh

368

193

Gas

Billion cubic feet

257

218

Gas

Billion cubic feet

205

257

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Gains and Losses from Derivative Instruments

The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships ~~during~~(dollars in thousands):


	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2020	2019	2018

Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(763)	(1,512)	(2,000)

(a)During the years ended December 31, 2020, 2019, and 2018, ~~and 2017 (dollars in thousands):~~we had 0 gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)Amounts are before the effect of PSA deferrals.

Financial Statement
Year Ended
December 31,
Commodity Contracts Location 2019 2018 2017
Loss Recognized in OCI on Derivative Instruments (Effective Portion) OCI — derivative instruments $ —
$ —
$ (59 )
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) Fuel and purchased power (b) (1,512 ) (2,000 ) (3,519 )


~~(a)~~	~~During the years ended December 31, 2019, 2018, and 2017, we had 0 losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.~~


~~(b)~~	~~Amounts are before the effect of PSA deferrals.~~

During the next twelve months, we estimate that ~~a net loss of $0.8 million before income taxes~~0 amounts will be reclassified from accumulated OCI ~~as an offset to~~into income. For APS, the ~~effect of market price changes~~delivery period for ~~the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and~~all derivative instruments in designated cash flow accounting hedging relationships have ~~no immediate effect on earnings.~~lapsed.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments ~~during the years ended December 31, 2019, 2018 and 2017~~ (dollars in thousands):


	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2020		2019		2018
Net Loss Recognized in Income	Operating revenues	$	0	$	0	$	(2,557)
Net Loss Recognized in Income	Fuel and purchased power (a)	(3,178)		(84,953)		(12,951)
Total		$	(3,178)	$	(84,953)	$	(15,508)

(a)Amounts are before the effect of PSA deferrals.

Financial Statement
Year Ended
December 31,
Commodity Contracts Location 2019 2018 2017
Net Loss Recognized in Income Operating revenues $ —
$ (2,557 ) $ (1,192 )
Net Loss Recognized in Income Fuel and purchased power (a) (84,953 ) (12,951 ) (87,991 )
Total $ (84,953 ) $ (15,508 ) $ (89,183 )


~~(a)~~	~~Amounts are before the effect of PSA deferrals.~~

Derivative Instruments in the Consolidated Balance Sheets

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

We do not offset a ~~counterparty's~~counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

to be offset in the event of a default. ~~Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.~~ These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.

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~~As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments.~~

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of ~~offsetting as of December 31, 2019 and 2018.~~offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.


As of December 31, 2020: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amount Reported on Balance Sheet
Current assets	$	5,870	$	(2,939)	$	2,931	$	0	$	2,931
Investments and other assets	3,150		(1,332)		1,818		0		1,818
Total assets	9,020		(4,271)		4,749		0		4,749

Current liabilities	(9,211)		2,939		(6,272)		(1,285)		(7,557)
Deferred credits and other	(12,394)		1,332		(11,062)		0		(11,062)
Total liabilities	(21,605)		4,271		(17,334)		(1,285)		(18,619)
Total	$	(12,585)	$	0	$	(12,585)	$	(1,285)	$	(13,870)

As of December 31, 2019:
(dollars in thousands)
Gross
Recognized
Derivatives
(a)

Amounts
Offset
(b)

Net
Recognized
Derivatives

Other
(c)

Amount
Reported on
Balance Sheet
Current assets $ 584
$ (474 ) $ 110
$ 405
$ 515

Current liabilities (38,235 ) 474
(37,761 ) (1,185 ) (38,946 )
Deferred credits and other (33,186 ) —
(33,186 ) —
(33,186 )
Total liabilities (71,421 ) 474
(70,947 ) (1,185 ) (72,132 )
Total $ (70,837 ) $ —
$ (70,837 ) $ (780 ) $ (71,617 )
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.


~~(a)~~	~~All of our gross recognized derivative instruments were subject to master netting arrangements.~~


~~(b)~~	~~NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.~~


~~(c)~~	Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of $405.

(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285.


As of December 31, 2019: (dollars in thousands)	Gross Recognized Derivatives (a)		Amounts Offset (b)		Net Recognized Derivatives		Other (c)		Amount Reported on Balance Sheet
Current assets	$	584	$	(474)	$	110	$	405	$	515



Current liabilities	(38,235)		474		(37,761)		(1,185)		(38,946)
Deferred credits and other	(33,186)		0		(33,186)		0		(33,186)
Total liabilities	(71,421)		474		(70,947)		(1,185)		(72,132)
Total	$	(70,837)	$	0	$	(70,837)	$	(780)	$	(71,617)

(a)All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of $405.

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As of December 31, 2018:
(dollars in thousands)
Gross
Recognized
Derivatives
(a)

Amounts
Offset
(b)

Net
Recognized
Derivatives

Other
(c)

Amount
Reported on
Balance Sheet
Current assets $ 3,106
$ (2,149 ) $ 957
$ 156
$ 1,113
Investments and other assets 36
(36 ) —
—
—
Total assets 3,142
(2,185 ) 957
156
1,113

Current liabilities (36,345 ) 2,149
(34,196 ) (1,310 ) (35,506 )
Deferred credits and other (24,567 ) 36
(24,531 ) —
(24,531 )
Total liabilities (60,912 ) 2,185
(58,727 ) (1,310 ) (60,037 )
Total $ (57,770 ) $ —
$ (57,770 ) $ (1,154 ) $ (58,924 )


~~(a)~~	~~All of our gross recognized derivative instruments were subject to master netting arrangements.~~


~~(b)~~	~~NaN cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.~~


~~(c)~~	Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Credit Risk and Credit Related Contingent Features

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, ~~2019,~~2020, we have four counterparties for which our exposure represents approximately 62% of Pinnacle ~~West has no counterparties with positive exposures of greater than 10%~~West’s $5 million of risk management assets. This exposure relates to master agreements with counterparties and all four are rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

The following table provides information about our derivative instruments that have credit-risk-related contingent features ~~at December 31, 2019~~ (dollars in thousands):

December 31, 2019
Aggregate fair value of derivative instruments in a net liability position $ 71,116
Cash collateral posted —
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a) 70,519


~~(a)~~	~~This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from~~December 31, 2020
Aggregate fair value of derivative instruments in a net liability position	$	21,605
Cash collateral posted	0
Additional cash collateral in the ~~derivative details above.~~event credit-risk related contingent features were fully triggered (a)	19,510

(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately ~~$95~~$90 million if our debt credit ratings were to fall below investment grade.

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~~18.~~

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. Other Income and Other Expense

The following table provides detail of Pinnacle ~~West's~~West’s Consolidated other income and other expense for 2020, 2019 ~~2018~~ and ~~2017~~2018 (dollars in thousands):


	2020			2019		2018
Other income:
Interest income	$	12,210		$	10,377	$	8,647
Investment gains (losses) — net	2,358			0		0
Debt return on Four Corners SCR deferral (Note 4)	26,121			19,541		16,153
Debt return on Ocotillo modernization project (Note 4)	15,865			20,282		0
Miscellaneous	149			63		96
Total other income	$	56,703		$	50,263	$	24,896
Other expense:
Non-operating costs	$	(12,400)		$	(10,663)	$	(10,076)
Investment gains (losses) — net	0			(1,835)		(417)
Miscellaneous	(45,376)		(a)	(5,382)		(7,473)
Total other expense	$	(57,776)		$	(17,880)	$	(17,966)

2019 2018 2017
Other income:

Interest income $ 10,377
$ 8,647
$ 3,497
Debt return on Four Corners SCR deferral (Note 4) 19,541
16,153
354
Debt return on Ocotillo modernization project (Note 4) 20,282
—
—
Miscellaneous 63
96
155
Total other income $ 50,263
$ 24,896
$ 4,006
Other expense:

Non-operating costs $ (10,663 ) $ (10,076 ) $ (11,749 )
Investment losses — net (1,835 ) (417 ) (4,113 )
Miscellaneous (5,382 ) (7,473 ) (5,677 )
Total other expense $ (17,880 ) $ (17,966 ) $ (21,539 )

(a)Miscellaneous includes donation of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2020, 2019 ~~2018~~ and ~~2017~~2018 (dollars in thousands):


	2020			2019		2018
Other income:
Interest income	$	9,621		$	6,998	$	6,496
Debt return on Four Corners SCR deferral (Note 4)	26,121			19,541		16,153
Debt return on Ocotillo modernization project (Note 4)	15,865			20,282		0
Miscellaneous	148			63		97
Total other income	$	51,755		$	46,884	$	22,746
Other expense:
Non-operating costs	$	(10,659)		$	(9,612)	$	(9,462)

Miscellaneous	(43,035)		(a)	(3,378)		(5,830)
Total other expense	$	(53,694)		$	(12,990)	$	(15,292)

2019 2018 2017
Other income:

Interest income $ 6,998
$ 6,496
$ 2,504
Debt return on Four Corners SCR deferral (Note 4) 19,541
16,153
354
Debt return on Ocotillo modernization project (Note 4) 20,282
—
—
Miscellaneous 63
97
155
Total other income $ 46,884
$ 22,746
$ 3,013
Other expense:

Non-operating costs $ (9,612 ) $ (9,462 ) $ (10,825 )
Miscellaneous (3,378 ) (5,830 ) (3,088 )
Total other expense $ (12,990 ) $ (15,292 ) $ (13,913 )

(a)Miscellaneous includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).

~~19.~~

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18. Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with 3 separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under 1 lease and 2033 under the other 2 leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period ~~2020~~2021 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, 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.

The ~~leases'~~leases’ terms give APS the ability to utilize the assets for a significant portion of the ~~assets'~~assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the ~~VIEs'~~VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2020, 2019 ~~2018~~ and ~~2017.~~2018. The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Consolidated Balance Sheets ~~at December 31, 2019 and December 31, 2018~~ include the following amounts relating to the VIEs (dollars in thousands):

December 31, 2019 December 31, 2018
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation $ 101,906
$ 105,775
Equity-Noncontrolling interests 122,540
125,790


	December 31, 2020		December 31, 2019
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	98,036	$	101,906
Equity-Noncontrolling interests	119,290		122,540

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our consolidated financial statements.

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately ~~$301~~$306 million beginning in ~~2020,~~2021, and up to $456 million over the lease extension ~~term.~~terms.

For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

~~20.~~19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security

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investments at their fair value on our Consolidated Balance Sheets. ~~See~~(See Note 1413 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy.) The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts — ~~- To~~APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo ~~Verde, APS established external decommissioning trusts in accordance with NRC regulations.~~Verde. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including ~~other-than-temporary impairments)~~credit losses) in other regulatory liabilities.

Coal Reclamation Escrow Account -— APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including ~~other-than-temporary impairments)~~credit losses) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.

Active Union Employee Medical Account -— APS has investments restricted for paying active union employee medical costs. ~~These investments were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018.~~ These investments may be used to pay active union employee medical costs incurred in the current and future periods. In ~~August~~2020 and 2019, ~~the Company~~APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including ~~other-than-temporary impairments)~~credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the tables below. On January 4, 2021, an additional $106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account (see Note 8).

184

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of ~~APS's~~APS’s nuclear decommissioning trust and other special use fund assets at December 31, ~~2019~~2020 and December 31, ~~2018~~2019 (dollars in thousands):


	December 31, 2020
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity Securities	$	639,851	$	37,337	$	677,188		$	421,666	$	0
Available for Sale-Fixed Income Securities	516,412		216,668		733,080		(a)	46,581		(398)
Other	(17,828)		504		(17,324)		(b)	0		0
Total	$	1,138,435	$	254,509	$	1,392,944		$	468,247	$	(398)

December 31, 2019
Fair Value
Total
Unrealized
Gains
Total
Unrealized
Losses
Investment Type: Nuclear Decommissioning Trusts
Other Special Use Funds
Total

Equity Securities $ 529,716

$ 7,142

$ 536,858

$ 337,681

$ —
Available for Sale-Fixed Income Securities 478,658

237,479

716,137
(a) 25,795

(669 )
Other 2,401

474

2,875
(b) —

—
Total $ 1,010,775

$ 245,095

$ 1,255,870

$ 363,476

$ (669 )
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.


~~(a)~~	~~As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.~~


~~(b)~~	~~Represents net pending securities sales and purchases.~~

(b)Represents net pending securities sales and purchases.


	December 31, 2019
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
Equity Securities	$	529,716	$	7,142	$	536,858		$	337,681	$	0
Available for Sale-Fixed Income Securities	478,658		237,479		716,137		(a)	25,795		(669)
Other	2,401		474		2,875		(b)	0		0
Total	$	1,010,775	$	245,095	$	1,255,870		$	363,476	$	(669)

(a)As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.

(b)Represents net pending securities sales and purchases.

185

December 31, 2018
Fair Value
Total
Unrealized
Gains
Total
Unrealized
Losses
Investment Type: Nuclear Decommissioning Trusts
Other Special Use Funds
Total

Equity Securities $ 402,008

$ 45,130

$ 447,138

$ 222,147

$ (459 )
Available for Sale-Fixed Income Securities 446,978

190,378

637,356
(a) 8,634

(6,778 )
Other 2,148

593

2,741
(b) —

—
Total $ 851,134

$ 236,101

$ 1,087,235

$ 230,781

$ (7,237 )


~~(a)~~	~~As of December 31, 2018, the amortized cost basis of these available-for-sale investments is $635 million.~~


~~(b)~~	~~Represents net pending securities sales and purchases.~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth ~~APS's~~APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2020, 2019 ~~2018~~ and ~~2017~~2018 (dollars in thousands):


	Year Ended December 31,
	Nuclear Decommissioning Trusts		Other Special Use Funds		Total
2020
Realized gains	$	12,194	$	176	$	12,370
Realized losses	(5,553)		(15)		(5,568)
Proceeds from the sale of securities (a)	675,035		144,484		819,519
2019
Realized gains	11,024		108		11,132
Realized losses	(6,972)		0		(6,972)
Proceeds from the sale of securities (a)	473,806		245,228		719,034
2018
Realized gains	6,679		1		6,680
Realized losses	(13,552)		0		(13,552)
Proceeds from the sale of securities (a)	554,385		98,648		653,033

Year Ended December 31,
Nuclear Decommissioning Trusts
Other Special Use Funds
Total
2019

Realized gains $ 11,024

$ 108

$ 11,132
Realized losses (6,972 )
—

(6,972 )
Proceeds from the sale of securities (a) 473,806

245,228

719,034
2018

Realized gains 6,679

1

6,680
Realized losses (13,552 )
—

(13,552 )
Proceeds from the sale of securities (a) 554,385

98,648

653,033
2017

Realized gains 21,813

17

21,830
Realized losses (13,146 )
(9 )
(13,155 )
Proceeds from the sale of securities (a) 542,246

4,093

546,339
(a)Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.


~~(a)~~	Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, ~~2019~~2020 is as follows (dollars in thousands):


	Nuclear Decommissioning Trusts		Coal Reclamation Escrow Account		Active Union Medical Trust		Total
Less than one year	$	19,563	$	33,079	$	0	$	52,642
1 year – 5 years	151,537		29,722		142,311		323,570
5 years – 10 years	133,307		2,738		0		136,045
Greater than 10 years	212,005		8,818		0		220,823
Total	$	516,412	$	74,357	$	142,311	$	733,080

Nuclear Decommissioning Trusts
Coal Reclamation Escrow Account
Active Union Medical Trust
Total
Less than one year $ 26,984

$ 31,953

$ 40,449

$ 99,386
1 year – 5 years 136,139

25,229

138,042

299,410
5 years – 10 years 105,797

—

—

105,797
Greater than 10 years 209,738

1,806

—

211,544
Total $ 478,658

$ 58,988

$ 178,491

$ 716,137

186

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~21.~~20. Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle ~~West's~~West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Pension and Other Postretirement Benefits			Derivative Instruments			Total
Balance at December 31, 2018	$	(45,997)		$	(1,711)		$	(47,708)
OCI (loss) before reclassifications	(14,041)			0			(14,041)
Amounts reclassified from accumulated other comprehensive loss	3,516		(a)	1,137		(b)	4,653

Balance at December 31, 2019	(56,522)			(574)			(57,096)
OCI (loss) before reclassifications	(8,370)			(2,089)			(10,459)
Amounts reclassified from accumulated other comprehensive loss	4,167		(a)	592		(b)	4,759

Balance at December 31, 2020	$	(60,725)		$	(2,071)		$	(62,796)

Pension and Other Postretirement Benefits Derivative Instruments Total
Balance December 31, 2017 $ (42,440 )
$ (2,562 )
$ (45,002 )
OCI (loss) before reclassifications 102

(78 )
24
Amounts reclassified from accumulated other comprehensive loss 4,295
(a) 1,527
(b) 5,822
Reclassification of income tax effect related to
tax reform (7,954 ) (598 ) (8,552 )
Balance December 31, 2018 (45,997 )
(1,711 )
(47,708 )
OCI (loss) before reclassifications (14,041 )
—

(14,041 )
Amounts reclassified from accumulated other comprehensive loss 3,516
(a) 1,137
(b) 4,653
Balance December 31, 2019 $ (56,522 )
$ (574 )
$ (57,096 )


~~(a)~~	~~These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8.~~


~~(b)~~	~~These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 17.~~

(a)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).

(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA (see Note 16).

Changes in Accumulated Other Comprehensive Loss -— APS

The following table shows the changes in ~~APS's~~APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, ~~2019~~2020 and ~~2018~~2019 (dollars in thousands):


	Pension and Other Postretirement Benefits			Derivative Instruments			Total
Balance at December 31, 2018	$	(25,396)		$	(1,711)		$	(27,107)
OCI (loss) before reclassifications	(12,572)			0			(12,572)
Amounts reclassified from accumulated other comprehensive loss	3,020		(a)	1,137		(b)	4,157

Balance at December 31, 2019	(34,948)			(574)			(35,522)
OCI (loss) before reclassifications	(9,568)			(18)			(9,586)
Amounts reclassified from accumulated other comprehensive loss	3,598		(a)	592		(b)	4,190

Balance at December 31, 2020	$	(40,918)		$	0		$	(40,918)

(a)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).

(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA (see Note 16).

187

Pension and Other Postretirement Benefits Derivative Instruments Total
Balance December 31, 2017 $ (24,421 )
$ (2,562 )
$ (26,983 )
OCI (loss) before reclassifications (326 )
(78 )
(404 )
Amounts reclassified from accumulated other comprehensive loss 3,791
(a) 1,527
(b) 5,318
Reclassification of income tax effect related to
tax reform (4,440 ) (598 ) (5,038 )
Balance December 31, 2018 (25,396 )
(1,711 )
(27,107 )
OCI (loss) before reclassifications (12,572 )
—

(12,572 )
Amounts reclassified from accumulated other comprehensive loss 3,020
(a) 1,137
(b) 4,157
Balance December 31, 2019 $ (34,948 )
$ (574 )
$ (35,522 )


~~(a)~~	~~These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 8.~~


~~(b)~~	~~These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 17.~~

Table of Contents

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

Year Ended December 31,
2019 2018 2017
Operating revenues $ —
$ —
$ 119
Operating expenses 12,451
53,844
24,591
Operating loss (12,451 ) (53,844 ) (24,472 )
Other

Equity in earnings of subsidiaries 562,946
569,249
507,495
Other expense (3,957 ) (3,202 ) (2,422 )
Total 558,989
566,047
505,073
Interest expense 15,069
12,074
5,633
Income before income taxes 531,469
500,129
474,968
Income tax benefit (6,851 ) (10,918 ) (13,488 )
Net income attributable to common shareholders 538,320
511,047
488,456
Other comprehensive income (loss) — attributable to common shareholders (9,388 ) 5,846
(1,180 )
Total comprehensive income — attributable to common shareholders $ 528,932
$ 516,893
$ 487,276


	Year Ended December 31,
	2020		2019		2018

Operating expenses	$	7,901	$	12,451	$	53,844

Other
Equity in earnings of subsidiaries	566,147		562,946		569,249
Other expense	(4,586)		(3,957)		(3,202)
Total	561,561		558,989		566,047
Interest expense	14,021		15,069		12,074
Income before income taxes	539,639		531,469		500,129
Income tax benefit	(10,920)		(6,851)		(10,918)
Net income attributable to common shareholders	550,559		538,320		511,047
Other comprehensive income (loss) — attributable to common shareholders	(5,700)		(9,388)		5,846
Total comprehensive income — attributable to common shareholders	$	544,859	$	528,932	$	516,893

See Combined Notes to Consolidated Financial Statements.

188

Table of Contents

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)

December 31,
2019 2018
ASSETS

Current assets

Cash and cash equivalents $ 19
$ 41
Accounts receivable 104,640
99,989
Income tax receivable 15,905
32,737
Other current assets 401
1,502
Total current assets 120,965
134,269
Investments and other assets

Investments in subsidiaries 6,067,957
5,859,834
Deferred income taxes 40,757
5,243
Other assets 50,139
34,910
Total investments and other assets 6,158,853
5,899,987
Total Assets $ 6,279,818
$ 6,034,256
LIABILITIES AND EQUITY

Current liabilities

Accounts payable $ 7,634
$ 9,565
Accrued taxes 8,573
9,006
Common dividends payable 87,982
82,675
Short-term borrowings 114,675
76,400
Current maturities of long-term debt 450,000
—
Operating lease liabilities 81
—
Other current liabilities 15,126
19,215
Total current liabilities 684,071
196,861

Long-term debt less current maturities (Note 7) (575 ) 448,796

Pension liabilities 17,942
17,766
Operating lease liabilities 1,780
—
Other 23,412
22,128
Total deferred credits and other 43,134
39,894
COMMITMENTS AND CONTINGENCIES (SEE NOTES)

Common stock equity
Common stock 2,650,134
2,629,440
Accumulated other comprehensive loss (57,096 ) (47,708 )
Retained earnings 2,837,610
2,641,183
Total Pinnacle West Shareholders’ equity 5,430,648
5,222,915
Noncontrolling interests 122,540
125,790
Total Equity 5,553,188
5,348,705
Total Liabilities and Equity $ 6,279,818
$ 6,034,256


	December 31,
	2020		2019
ASSETS
Current assets
Cash and cash equivalents	$	19	$	19
Accounts receivable	123,980		104,640

Income tax receivable	14,719		15,905
Other current assets	298		401
Total current assets	139,016		120,965
Investments and other assets
Investments in subsidiaries	6,400,339		6,067,957
Deferred income taxes	7,589		40,757
Other assets	52,595		50,139
Total investments and other assets	6,460,523		6,158,853
Total Assets	$	6,599,539	$	6,279,818
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	5,669	$	7,634
Accrued taxes	16,998		8,573
Common dividends payable	93,531		87,982
Short-term borrowings	169,000		114,675
Current maturities of long-term debt	0		450,000
Operating lease liabilities	90		81
Other current liabilities	15,306		15,126
Total current liabilities	300,594		684,071

Long-term debt less current maturities (Note 7)	496,321		(575)



Pension liabilities	17,541		17,942
Operating lease liabilities	1,683		1,780
Other	30,607		23,412
Total deferred credits and other	49,831		43,134
COMMITMENTS AND CONTINGENCIES (SEE NOTES)	0		0
Common stock equity
Common stock	2,671,193		2,650,134
Accumulated other comprehensive loss	(62,796)		(57,096)
Retained earnings	3,025,106		2,837,610
Total Pinnacle West Shareholders’ equity	5,633,503		5,430,648
Noncontrolling interests	119,290		122,540
Total Equity	5,752,793		5,553,188
Total Liabilities and Equity	$	6,599,539	$	6,279,818

See Combined Notes to Consolidated Financial Statements.

189

Table of Contents

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)

Year Ended December 31,
2019 2018 2017
Cash flows from operating activities

Net income $ 538,320
$ 511,047
$ 488,456
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net (562,946 ) (569,249 ) (507,495 )
Depreciation and amortization 76
76
76
Deferred income taxes (35,831 ) 49,535
(264 )
Accounts receivable 182
(7,881 ) (2,106 )
Accounts payable (2,129 ) 1,967
(11,162 )
Accrued taxes and income tax receivables — net 16,400
(13,535 ) (22,247 )
Dividends received from subsidiaries 336,300
316,000
296,800
Other (1,300 ) 31,807
15,092
Net cash flow provided by operating activities 289,072
319,767
257,150
Cash flows from investing activities

Investments in subsidiaries 1,557
(142,796 ) (178,027 )
Repayments of loans from subsidiaries 4,190
6,477
2,987
Advances of loans to subsidiaries (4,165 ) (500 ) (6,388 )
Net cash flow provided by (used for) investing activities 1,582
(136,819 ) (181,428 )
Cash flows from financing activities

Issuance of long-term debt —
150,000
298,761
Short-term debt borrowings under revolving credit facility 49,000
20,000
58,000
Short-term debt repayments under revolving credit facility (65,000 ) (32,000 ) (32,000 )
Commercial paper - net 54,275
(7,000 ) 27,700
Dividends paid on common stock (329,643 ) (308,892 ) (289,793 )
Repayment of long-term debt —
—
(125,000 )
Common stock equity issuance - net of purchases 692
(5,055 ) (13,390 )
Other —
(1 ) —
Net cash flow used for financing activities (290,676 ) (182,948 ) (75,722 )
Net decrease in cash and cash equivalents (22 ) —
—
Cash and cash equivalents at beginning of year 41
41
41
Cash and cash equivalents at end of year $ 19
$ 41
$ 41


	Year Ended December 31,
	2020		2019		2018
Cash flows from operating activities
Net income	$	550,559	$	538,320	$	511,047
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(566,147)		(562,946)		(569,249)
Depreciation and amortization	76		76		76
Deferred income taxes	33,007		(35,831)		49,535
Accounts receivable	(7,903)		182		(7,881)
Accounts payable	(1,964)		(2,129)		1,967
Accrued taxes and income tax receivables — net	9,610		16,400		(13,535)
Dividends received from subsidiaries	357,500		336,300		316,000
Other	20,163		(1,300)		31,807
Net cash flow provided by operating activities	394,901		289,072		319,767
Cash flows from investing activities

Investments in subsidiaries	(137,881)		1,557		(142,796)
Repayments of loans from subsidiaries	932		4,190		6,477
Advances of loans to subsidiaries	(7,261)		(4,165)		(500)
Net cash flow provided by (used for) investing activities	(144,210)		1,582		(136,819)
Cash flows from financing activities
Issuance of long-term debt	496,950		0		150,000
Short-term debt borrowings under revolving credit facility	211,690		49,000		20,000
Short-term debt repayments under revolving credit facility	(230,690)		(65,000)		(32,000)
Commercial paper — net	73,325		54,275		(7,000)
Dividends paid on common stock	(350,577)		(329,643)		(308,892)
Repayment of long-term debt	(450,000)		0		0
Common stock equity issuance — net of purchases	(1,389)		692		(5,055)
Other	0		0		(1)
Net cash flow used for financing activities	(250,691)		(290,676)		(182,948)
Net decrease in cash and cash equivalents	0		(22)		0
Cash and cash equivalents at beginning of year	19		41		41
Cash and cash equivalents at end of year	$	19	$	19	$	41

See Combined Notes to Consolidated Financial Statements.

190

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.

191

~~PINNACLE WEST CAPITAL CORPORATION~~

~~SCHEDULE II — RESERVE FOR UNCOLLECTIBLES~~

~~(dollars in thousands)~~

Column A Column B Column C Column D Column E
Additions
Description
Balance at
beginning
of period

Charged to
cost and
expenses

Charged
to other
accounts
Deductions
Balance
at end of
period
Reserve for uncollectibles:

2019 $ 4,069
$ 11,819
$ —
$ 7,717
$ 8,171
2018 2,513
10,870
—
9,314
4,069
2017 3,037
6,836
—
7,360
2,513

Table of Contents

~~ARIZONA PUBLIC SERVICE COMPANY~~

~~SCHEDULE II — RESERVE FOR UNCOLLECTIBLES~~

~~(dollars in thousands)~~

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a)Disclosure Controls and Procedures

The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, ~~2019.~~2020. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of December 31, ~~2019.~~2020. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective.

(b)Management’s Annual Reports on Internal Control Over Financial Reporting

Reference is made to “Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)” in Item 8 of this report and “Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)” in Item 8 of this report.

(c)Attestation Reports of the Registered Public Accounting Firm

Reference is made to “Report of Independent Registered Public Accounting Firm” in Item 8 of this report and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report on the internal control over financial reporting of Pinnacle West Capital Corporation and Arizona Public Service Company, respectively.

(d)Changes In Internal Control Over Financial Reporting

No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended December 31, ~~2019~~2020 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

192

Table of Contents

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS

AND CORPORATE GOVERNANCE OF PINNACLE WEST

Reference is hereby made to “Information About Our Board and Corporate Governance” and “Proposal 1 — Election of Directors” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May ~~20, 2020~~19, 2021 (the ~~“2020~~“2021 Proxy Statement”) and to the “Information about our Executive Officers” section in Part I of this report.

Pinnacle West has adopted a Code of Ethics for Financial Executives that applies to financial executives including Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller, Treasurer, and General Counsel, the President and Chief Operating Officer of APS and other persons designated as financial executives by the Chair of the Audit Committee. The Code of Ethics for Financial Executives is posted on Pinnacle West’s website (www.pinnaclewest.com). Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Executives by posting such information on Pinnacle West’s website.

ITEM 11. EXECUTIVE COMPENSATION

Reference is hereby made to “Director Compensation,” “Executive Compensation,” and “Human Resources Committee Interlocks and Insider Participation” in the ~~2020~~2021 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF

CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS

Reference is hereby made to “Ownership of Pinnacle West Stock” and “Existing Equity Compensation Plans” in the ~~2020~~2021 Proxy Statement.

~~Securities Authorized for Issuance Under Equity Compensation Plans~~

The following table sets forth information as of December 31, 2019 with respect to the 2012 Plan and the 2007 Plan, under which our equity securities are outstanding or currently authorized for issuance.

~~Equity Compensation Plan Information~~

Plan Category
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
(a)

Weighted-
average exercise price
of outstanding
options,
warrants and
rights
(b)

Number of
securities remaining
available for future
issuance under
equity
compensation plans
(excluding
securities reflected
in column (a))
(c)
Equity compensation plans approved by security holders 1,267,062
—
1,645,994
Equity compensation plans not approved by security holders —

Total 1,267,062
—
1,645,994

~~(a)~~

This amount includes shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.


~~(b)~~	~~The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.~~

~~(c)~~

Awards under the 2012 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units. Additional shares cannot be awarded under the 2007 Plan. However, if an award under the 2012 Plan is forfeited, terminated or canceled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation or expiration, may be added back to the shares available for issuance under the 2012 Plan.

~~Equity Compensation Plans Approved By Security Holders~~

Amounts in column (a) in the table above include shares subject to awards outstanding under two equity compensation plans that were previously approved by our shareholders: (a) the 2007 Plan, which was approved by our shareholders at our 2007 annual meeting of shareholders and under which no new stock awards may be granted; and (b) the 2012 Plan, as amended, which was approved by our shareholders at our 2012 annual meeting of shareholders and the first amendment to the 2012 Plan was approved by our shareholders at our 2017 annual meeting of shareholders. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.

~~Equity Compensation Plans Not Approved by Security Holders~~

~~The Company does not have any equity compensation plans under which shares can be issued that have not been approved by the shareholders.~~

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED

TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the ~~2020~~2021 Proxy Statement.

193

Table of Contents

ITEM 14. PRINCIPAL ACCOUNTANT

FEES AND SERVICES

Pinnacle West

Reference is hereby made to “Audit Matters — Audit Fees and — Pre-Approval Policies” in the ~~2020~~2021 Proxy Statement.

APS

The following fees were paid to APS’s independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:


Type of Service	2019		2018		Type of Service	2020		2019
Audit Fees (1)	$	2,328,565	$	2,342,455	Audit Fees (1)	$	2,414,909	$	2,328,565
Audit-Related Fees (2)	322,917		300,334		Audit-Related Fees (2)	323,067		322,917

(1) The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.

(2) The aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits performed in ~~2019~~2020 and ~~2018.~~2019.

Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’s registered public accounting firm. The Audit Committee has delegated to the Chair of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than ~~$50,000.~~$100,000. The Chair must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS in ~~2019~~2020 were pre-approved by the Audit Committee or the Chair consistent with the pre-approval policy.

194

Table of Contents

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.

Exhibits Filed

The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

~~Exhibit~~

~~No.~~

3.1

~~Registrant(s)~~Pinnacle West

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~3.1~~

~~Pinnacle West~~

Articles of Incorporation, restated as of May 21, 2008

3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962

8/7/2008

3.2

Pinnacle West

Pinnacle West Capital Corporation Bylaws, amended as of February ~~22, 2017~~19, 2020

3.1 to Pinnacle West/APS February ~~28, 2017~~25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473

2/~~28/2017~~25/2020

3.3

APS

Articles of Incorporation, restated as of May 25, 1988

4.2 to APS’s Form 18 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473

9/29/1993

3.3.1

APS

Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012

3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473

5/22/2012

3.4

APS

Arizona Public Service Company Bylaws, amended as of December 16, 2008

3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473

2/20/2009

4.1

Pinnacle West

Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value

4.1 to Pinnacle West June 20, 2017 Form 8-K Report, File No. 1-8962

6/20/2017

4.2

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Indenture dated as of January 1, 1995 among APS and The Bank of New York Mellon, as Trustee

4.6 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473

1/11/1995

~~4.2a~~4.3

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

~~First Supplemental Indenture dated as of January 1, 1995~~

~~4.4 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473~~

~~1/11/1995~~

~~4.3~~

~~Pinnacle West~~

~~APS~~

Indenture dated as of November 15, 1996 between APS and The Bank of New York, as Trustee

4.5 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473

11/22/1996

~~Exhibit~~

~~No.~~

4.4

~~Registrant(s)~~Pinnacle West

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~4.3a~~

~~Pinnacle West~~

~~APS~~

~~First Supplemental Indenture dated as of November 15, 1996~~

~~4.6 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473~~

~~11/22/1996~~

~~4.3b~~

~~Pinnacle West~~

~~APS~~

~~Second Supplemental Indenture dated as of April 1, 1997~~

~~4.10 to APS’s Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473~~

~~4/9/1997~~

~~4.3c~~

~~Pinnacle West~~

~~APS~~

~~Third Supplemental Indenture dated as of November 1, 2002~~

~~10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962~~

~~5/15/2003~~

~~4.4~~

~~Pinnacle West~~

Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Unsecured Debt Securities

4.1 to Pinnacle West’s Registration Statement No. 333-52476

12/21/2000

195

Table of Contents

~~4.4a~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

4.4a

Pinnacle West

~~Third~~Fourth Supplemental Indenture dated as of ~~November 30, 2017~~June 17, 2020

4.1 to Pinnacle West ~~November 30, 2017~~June 10, 2020 Form 8-K Report, File No. 1-8962

~~11/30/2017~~6/16/2020

4.5

Pinnacle West

Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Subordinated Unsecured Debt Securities

4.2 to Pinnacle West’s Registration Statement No. 333-52476

12/21/2000

4.6

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Indenture dated as of January 15, 1998 between APS and The Bank of New York Mellon Trust Company N.A. (successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank), as Trustee

4.10 to APS’s Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473

1/16/1998

4.6a

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Seventh Supplemental Indenture dated as of May 1, 2003

4.1 to APS’s Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473

5/9/2003

4.6b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

~~Eighth Supplemental Indenture dated as of June 15, 2004~~

~~4.1 to APS’s Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473~~

~~6/28/2004~~

~~4.6c~~

~~Pinnacle West~~

~~APS~~

Ninth Supplemental Indenture dated as of August 15, 2005

4.1 to APS’s Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473

8/22/2005

~~4.6d~~4.6c

APS

Tenth Supplemental Indenture dated as of August 1, 2006

4.1 to APS’s July 31, 2006 Form 8-K Report, File No. 1-4473

8/3/2006

~~4.6e~~4.6d

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

~~Eleventh Supplemental Indenture dated as of February 26, 2009~~

~~4.6e to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473~~

~~2/20/2015~~

~~4.6f~~

~~Pinnacle West~~

~~APS~~

Twelfth Supplemental Indenture dated as of August 25, 2011

4.6f to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/20/2015

~~4.6g~~4.6e

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Thirteenth Supplemental Indenture dated as of January 13, 2012

4.6g to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/20/2015

~~Exhibit~~

~~No.~~

4.6f

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~4.6h~~

~~Pinnacle West~~

~~APS~~

Fourteenth Supplemental Indenture dated as of January 10, 2014

4.6h to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/20/2015

~~4.6i~~4.6g

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Fifteenth Supplemental Indenture dated as of June 18, 2014

4.6i to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/20/2015

~~4.6j~~4.6h

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

~~Sixteenth Supplemental Indenture dated as of January 12, 2015~~

~~4.6j to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473~~

~~2/20/2015~~

~~4.6k~~

~~Pinnacle West~~

~~APS~~

Seventeenth Supplemental Indenture dated as of May 19, 2015

4.1 to Pinnacle West/APS May 14, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473

5/19/2015

~~4.6l~~4.6i

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Eighteenth Supplemental Indenture dated as of November 6, 2015

4.1 to Pinnacle West/APS November 3, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473

11/6/2015

~~4.6m~~4.6j

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Nineteenth Supplemental Indenture dated as of May 6, 2016

4.1 to Pinnacle West/APS May 3, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473

5/6/2016

~~4.6n~~4.6k

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Twentieth Supplemental Indenture dated as of September 20, 2016

4.1 to Pinnacle West/APS September 15, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473

9/20/2016

~~4.6o~~4.6l

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Twenty-First Supplemental Indenture dated as of September 11, 2017

4.1 to Pinnacle West/APS September 11, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473

9/11/2017

196

Table of Contents

~~4.6p~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

4.6m

Pinnacle West

APS

Twenty-Second Supplemental Indenture dated as of August 9, 2018

4.1 to Pinnacle West/APS August 9, 2018 Form 8-K Report, File Nos. 1-8962 and 1-4473

8/9/2018

~~4.6q~~4.6n

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Twenty-Third Supplemental Indenture dated as of February 28, 2019

4.1 to Pinnacle West/APS February 28, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473

2/28/2019

~~4.6r~~4.6o

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Twenty-Fourth Supplemental Indenture dated as of August 19, 2019

4.1 to Pinnacle West/APS August 16, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473

8/16/2019

~~4.6s~~4.6p

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Twenty-Fifth Supplemental Indenture dated as of November 20, 2019

4.1 to Pinnacle West/APS November 20, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473

11/20/2019

~~4.7~~4.6q

Pinnacle West
APS

Twenty-Sixth Supplemental Indenture dated as of May 22, 2020

4.1 to Pinnacle West/APS May 22, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473

5/22/2020

4.6r

Pinnacle West
APS

Twenty-Seventh Supplemental Indenture dated as of September 11, 2020

4.1 to Pinnacle West/APS September 11, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473

9/11/2020

4.7

Pinnacle West

Second Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of June 23, 2004

4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962

8/9/2004

4.7a

Pinnacle West

Third Amended and Restated Pinnacle West Capital Corporation Investors Advantage Plan dated as of November 25, 2008

4.1 to Pinnacle West’s Form S-3 Registration Statement No. 333-155641, File No. 1-8962

11/25/2008

4.8

Pinnacle West

Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets

4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962

3/30/1988

~~Exhibit~~

~~No.~~

4.8a

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~4.8a~~

~~Pinnacle West~~

~~APS~~

Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’s total assets

4.1 to APS’s 1993 Form 10-K Report, File No. 1-4473

3/30/1994

4.9

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934

10.1.1

Pinnacle West

APS

Two separate Decommissioning Trust Agreements (relating to PVGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee

10.2 to APS’s September 30, 1991 Form 10-Q Report, File No. 1-4473

11/14/1991

10.1.1a

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 1 to Decommissioning Trust Agreement (PVGS Unit 1), dated as of December 1, 1994

10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473

3/30/1995

10.1.1b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 1 to Decommissioning Trust Agreement (PVGS Unit 3), dated as of December 1, 1994

10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473

3/30/1995

197

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

~~10.1.1c~~

10.1.1c

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 2 to APS Decommissioning Trust Agreement (PVGS Unit 1) dated as of July 1, 1991

10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473

3/28/1997

10.1.1d

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 2 to APS Decommissioning Trust Agreement (PVGS Unit 3) dated as of July 1, 1991

10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473

3/28/1997

10.1.1e

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 3 to the Decommissioning Trust Agreement (PVGS Unit 1), dated as of March 18, 2002

10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962

5/15/2002

10.1.1f

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 3 to the Decommissioning Trust Agreement (PVGS Unit 3), dated as of March 18, 2002

10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962

5/15/2002

10.1.1g

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 4 to the Decommissioning Trust Agreement (PVGS Unit 1), dated as of December 19, 2003

10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962

3/15/2004

10.1.1h

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 4 to the Decommissioning Trust Agreement (PVGS Unit 3), dated as of December 19, 2003

10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962

3/15/2004

10.1.1i

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 5 to the Decommissioning Trust Agreement (PVGS Unit 1), dated as of May 1, 2007

10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/9/2007

10.1.1j

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 5 to the Decommissioning Trust Agreement (PVGS Unit 3), dated as of May 1, 2007

10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473

5/9/2007

~~Exhibit~~

~~No.~~

10.1.2

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.1.2~~

Pinnacle West

APS

Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVGS Unit 2

10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962

3/26/1992

10.1.2a

Pinnacle West

APS

First Amendment to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of November 1, 1992

10.2 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

10.1.2b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of November 1, 1994

10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473

3/30/1995

198

Table of Contents

~~10.1.2c~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.1.2c

Pinnacle West

APS

Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of June 20, 1996

10.1 to APS’s June 30, 1996 Form 10-Q Report, File No. 1-4473

8/9/1996

10.1.2d

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2) dated as of December 16, 1996

APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473

3/28/1997

10.1.2e

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of June 30, 2000

10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962

5/15/2002

10.1.2f

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of March 18, 2002

10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962

5/15/2002

10.1.2g

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of December 19, 2003

10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962

3/15/2004

10.1.2h

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of April 1, 2007

10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962

2/27/2008

10.2.1^b

Pinnacle West

APS

Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively

10.4 to APS’s 1988 Form 10-K Report, File No. 1-4473

3/8/1989

10.2.1a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993

10.3A to APS’s 1993 Form 10-K Report, File No. 1-4473

3/30/1994

~~Exhibit~~

~~No.~~10.2.1bb

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.2.1b~~^b

~~Pinnacle West~~

~~APS~~

Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993

10.2 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473

11/10/1994

10.2.1c^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997

10.3A to APS’s 1996 Form 10-K Report, File No. 1-4473

3/28/1997

10.2.1d^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001

10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962

3/14/2001

10.2.2^b

Pinnacle West

APS

Arizona Public Service Company Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986

10.1 to APS’s June 30, 1986 Form 10-Q Report, File No. 1-4473

8/13/1986

199

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.2.2a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993

10.2A to APS’s 1993 Form 10-K Report, File No. 1-4473

3/30/1994

10.2.2b^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993

10.1 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473

11/10/1994

10.2.2c^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999

10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962

3/30/2000

10.2.3^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996

10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962

3/30/2000

10.2.3a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans

10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962

3/30/2000

10.2.4^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996

10.10A to APS’s 1995 Form 10-K Report, File No. 1-4473

3/29/1996

10.2.4a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan

10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962

3/30/2000

~~Exhibit~~

~~No.~~10.2.4bb

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.2.4b~~^b

~~Pinnacle West~~

~~APS~~

Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan

10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962

3/30/2000

10.2.4c^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002

10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962

5/15/2003

200

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.2.4d^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003

10.64b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/13/2006

10.2.5^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (as amended and restated effective January 1, 2016)

10.2.5 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/19/2016

10.3.1^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, amended and restated as of January 1, 2003

10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962

3/15/2004

10.3.1a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003

10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/13/2006

10.3.2^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)

10.3.2 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/19/2016

10.3.2a^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

First Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)

10.3.2a to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/24/2017

10.3.2b^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Second Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005 (as amended and restated effective January 1, 2016)

10.3.2b to Pinnacle West/APS 2017 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/23/2018

10.4.1^b

Pinnacle West
APS

~~Consulting Services Agreement between Pinnacle West and Donald E. Brand~~

~~10.1 to Pinnacle West/APS September 30, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473~~

~~11/7/2019~~

~~10.4.2~~^b

~~Pinnacle West~~

~~APS~~

Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield

10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/7/2008

~~Exhibit~~

~~No.~~10.4.2b

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.4.3~~^b

~~APS~~

~~Retention Agreement dated December 19, 2008 between APS and Robert Bement~~

~~10.4.2 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473~~

~~2/22/2019~~

~~10.4.4~~^b

~~APS~~

~~Discretionary Credit Award Agreement dated October 20, 2014 between APS and Robert Bement~~

~~10.4.3 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473~~

~~2/22/2019~~

~~10.4.5~~^b

~~Pinnacle West~~

~~APS~~

Offer of Employment Letter dated July 19, 2018 between Pinnacle West and Robert E. Smith

10.4.5 to Pinnacle West/APS 2019 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/21/2020

~~10.4.6~~10.4.3^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Supplemental Agreement dated October 17, 2018 between Pinnacle West and Robert E. Smith

10.4.6 to Pinnacle West/APS 2019 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/21/2020

10.4.4b

Pinnacle West
APS

Discretionary Credit Award Agreement dated June 19, 2019 between Pinnacle West and Theodore Geisler

10.4.5ab

Pinnacle West
APS

Retention Agreement dated December 19, 2008 between APS and Maria Lacal

201

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.4.5bb

Pinnacle West
APS

First Amendment to the Retention Agreement dated May 24, 2011 between APS and Maria Lacal

10.4.6b

Pinnacle West
APS

Medical Retention Agreement dated October 31, 2014 between APS and Maria Lacal

10.4.7b

Pinnacle West
APS

Discretionary Credit Award Agreement dated October 31, 2014 between APS and Maria Lacal

10.4.8b

Pinnacle West
APS

Discretionary Credit Award Agreement dated September 29, 2016 between APS and Maria Lacal

10.5.1^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries

10.77bd to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/13/2006

10.5.1a^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473

11/6/2007

10.5.2^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473

11/6/2007

10.5.3^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.5.3 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/19/2010

10.5.4^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries

10.5.4 to Pinnacle West/APS 2012 Form 10-K, File Nos. 1-8962 and 1-4473

2/22/2013

10.6.1^b

Pinnacle West

Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962

4/20/2007

10.6.1a^b

Pinnacle West

First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962

4/20/2007

10.6.1b^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/5/2009

10.6.1c^bd

Pinnacle West

Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962

8/3/2010

10.6.1d^bd

Pinnacle West

Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.2 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962

8/3/2010

202

Table of Contents

~~Exhibit~~

~~No.~~

~~Registrant(s)~~

~~Description~~

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.6.1e^bd

Pinnacle West

Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.4 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962

4/29/2011

10.6.1f^bd

Pinnacle West

Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan

10.5 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962

4/29/2011

10.6.1g^bd

Pinnacle West

Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan (Supplemental 2010 Award)

10.6 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962

4/29/2011

10.6.2^b

Pinnacle West

Description of Annual Stock Grants to Non-Employee Directors

10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962

11/6/2007

10.6.3^b

Pinnacle West

Description of Annual Stock Grants to Non-Employee Directors

10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962

8/7/2008

10.6.4^bd

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Summary of ~~2020~~2021 Variable Incentive Plan and Officer Variable Incentive Plan

~~10.6.5~~

~~Pinnacle West~~

~~Description of Restricted Stock Unit Grant to Donald E. Brandt~~

~~Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-8962~~

~~12/26/2012~~

~~10.6.6~~10.6.5^b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

Appendix A to the Proxy Statement for Pinnacle West’s 2012 Annual Meeting of Shareholders, File No. 1-8962

3/29/2012

~~10.6.6a~~10.6.5a^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.1 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/3/2012

~~10.6.6b~~10.6.5b^bd

Pinnacle West

Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.2 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/3/2012

~~10.6.6c~~10.6.5c^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.8c to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/21/2014

~~10.6.6d~~10.6.5d^bd

Pinnacle West

Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.8d to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/21/2014

~~10.6.6e~~10.6.5e^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.6e to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/19/2016

~~10.6.6f~~10.6.5f^bd

Pinnacle West

Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.6f to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/24/2017

203

Table of Contents

~~Exhibit~~

~~No.~~

~~Registrant(s)~~

~~Description~~

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

~~10.6.6g~~10.6.5g^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.6g to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/24/2017

~~10.6.6h~~10.6.5h^bd

Pinnacle West

Form of Restricted Stock Unit Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.2 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/1/2019

~~10.6.6i~~10.6.5i^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.3 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/1/2019

~~10.6.6j~~10.6.5j^bd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.1 to Pinnacle West/APS March 31, 2020 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/8/2020

10.6.5kbd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.5lbd

Pinnacle West

Form of Performance Share Award Agreement under the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

10.6.5mbd

Pinnacle West

Master Amendment to Performance Share Agreements

10.3 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/3/2012

~~10.6.6k~~10.6.5n^bd

Pinnacle West

Master Amendment to Restricted Stock Unit Agreements

10.4 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/3/2012

~~10.6.6l~~10.6.5o^bd

Pinnacle West

~~Performance Cash Award Agreement, dated May 10, 2017, between Pinnacle West and Donald E. Brandt~~

~~10.1 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473~~

~~5/2/2017~~

~~10.6.6m~~^bd

~~Pinnacle West~~

First Amendment to the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan

Appendix A to the Proxy Statement for Pinnacle West’s 2017 Annual Meeting of Shareholders, File No. 1-8962

3/31/2017

10.7.1

Pinnacle West

APS

Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant

5.01 to ~~APS's~~APS’s Form S-7 Registration Statement, File No. 2-59644

9/1/1977

10.7.1a

Pinnacle West

APS

Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant

5.02 to APS’s Form S-7 Registration Statement, File No. 2-59644

9/1/1977

10.7.1b

Pinnacle West

APS

Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985

10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-89

7/25/1985

10.7.1c

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment and Supplement No. 2 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011

10.1 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473

4/29/2011

10.7.1d

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment and Supplement No. 3 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011

10.2 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473

4/29/2011

204

Table of Contents

~~10.7.2~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.7.2

Pinnacle West

APS

Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site

5.04 to APS’s Form S-7 Registration Statement, File No. 2-59644

9/1/1977

10.7.2a

Pinnacle West

APS

Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Site dated April 25, 1985

10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962

7/25/1985

~~Exhibit~~

~~No.~~

10.7.3

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.7.3~~

Pinnacle West

APS

Application and Grant of APS rights- of-way and easements, Four Corners Site

5.05 to APS’s Form S-7 Registration Statement, File No. 2-59644

9/1/1977

10.7.3a

Pinnacle West

APS

Application and Amendment No. 1 to Grant of APS rights-of-way and easements, Four Corners Site dated April 25, 1985

10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962

7/25/1985

10.7.4

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Four Corners Project Co-Tenancy Agreement, conformed copy up through and including Amendment No. 11, dated June 30, 2018, among APS, Public Service Company of New Mexico, SRP, Tucson Electric Power Company and Navajo Transitional Energy Company, LLC

10.7.4c to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2018

10.8.1

Pinnacle West

APS

Indenture of Lease, Navajo Units 1, 2, and 3

5(g) to APS’s Form S-7 Registration Statement, File No. 2-36505

3/23/1970

10.8.2

Pinnacle West

APS

Application of Grant of rights-of-way and easements, Navajo Plant

5(h) to APS Form S-7 Registration Statement, File No. 2-36505

3/23/1970

10.8.3

Pinnacle West

APS

Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant

5(l) to APS’s Form S-7 Registration Statement, File No. 2-394442

3/16/1971

10.8.4

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998

10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/13/2006

10.8.5

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971

10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/13/2006

205

Table of Contents

~~10.9.1~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.9.1

Pinnacle West

APS

ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto

10. 1 to APS’s 1988 Form 10-K Report, File No. 1-4473

3/8/1989

~~Exhibit~~

~~No.~~

10.9.1a

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.9.1a~~

Pinnacle West

APS

Amendment No. 13, dated as of April 22, 1991, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles

10.1 to APS’s March 31, 1991 Form 10-Q Report, File No. 1-4473

5/15/1991

10.9.1b

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 14 to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles

99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962

8/14/2000

10.9.1c

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 15, dated November 29, 2010, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles

10.9.1c to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/18/2011

10.9.1d

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 16, dated April 28, 2014, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles

10.2 to Pinnacle West/APS March 31, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/2/2014

10.10.1

Pinnacle West

APS

Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991

10.1 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473

8/8/1991

10.10.2

Pinnacle West

APS

Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991

10.2 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473

8/8/1991

10.10.2a

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS

10.3 to APS’s 1995 Form 10-K Report, File No. 1-4473

3/29/1996

~~10.10.3~~

~~Pinnacle West~~

~~APS~~

~~Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995~~

~~10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473~~

~~3/29/1996~~

206

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

~~Exhibit~~

~~No.~~

10.10.3

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ aRestated Transmission Agreement between PacifiCorp and APS dated April 5, 1995

~~Date Filed~~10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473

3/29/1996

~~10.10.4~~

10.10.4

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Contract among PacifiCorp, APS and DOE Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995

10.5 to APS’s 1995 Form 10-K Report, File No. 1-4473

3/29/1996

10.10.5

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994

10.6 to APS’s 1995 Form 10-K Report, File No. 1-4473

3/29/1996

10.11.1

~~Pinnacle West~~

Term Loan Agreement dated as of December 21, 2018 among Pinnacle West, as Borrower, KeyBank National Association, as Agent, PNC Bank, National Association and Wells Fargo Bank, National Association, as Co-Syndication Agents and such institutions compromising the lenders party thereto

~~10.4.2 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473~~

~~2/22/2019~~

~~10.11.2~~

Pinnacle West APS

Term Loan Agreement dated as of February 26, 2019 among APS, as Borrower, SunTrust Bank, as Agent, SunTrust Bank, TD Bank, N.A., U.S. Bank National Association and The Bank of Nova Scotia, as Co-Syndication Agents and such institutions compromising the lenders party thereto

10.1 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/1/2019

~~10.11.3~~10.11.2

Pinnacle West

Five-Year Credit Agreement dated as of July 12, 2018, among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

10.3 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2018

~~10.11.4~~10.11.3

Pinnacle West

364-Day Term Loan, dated as of May ~~9, 2019,~~5, 2020, among Pinnacle West, as Borrower, PNC Bank, National Association, as Agent ~~and Citibank, as Syndication Agent~~

~~10.1~~10.2 to Pinnacle West/APS ~~June 30, 2019~~March 31, 2020 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/8/~~8/2019~~2020

~~10.11.5~~10.11.4

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Five-Year Credit Agreement dated as of June 29, 2017 among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

10.2 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2017

~~10.11.5a~~10.11.4a

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 1, dated July 13, 2018, to Five-Year Credit Agreement dated as of June 29, 2017, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

10.11.4a to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2018

~~Exhibit~~

~~No.~~

10.11.5

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.11.6~~

~~Pinnacle West~~

~~APS~~

Five-Year Credit Agreement dated as of July 12, 2018 among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto

10.4 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2018

10.12.1^c

Pinnacle West

APS

Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee

4.3 to APS’s Form 18 Registration Statement, File No. 33-9480

10/24/1986

207

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.12.1a^c

Pinnacle West

APS

Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee

10.5 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473

12/4/1986

10.12.1b^c

Pinnacle West

APS

Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee

10.3 to APS’s 1988 Form 10-K Report, File No. 1-4473

3/8/1989

10.12.1c^c

Pinnacle West

APS

Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee

10.3 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

10.12.1d^c

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 4, dated as of September 30, 2015, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under a Trust Agreement with Emerson Finance LLC, as Lessor, and APS, as Lessee

10.2 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473

10/30/2015

~~Exhibit~~

~~No.~~10.12.1ec

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.12.1e~~^c

~~Pinnacle West~~

~~APS~~

Amendment No. 3, dated as of September 30, 2015, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation, as Lessor, and APS, as Lessee

10.3 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473

10/30/2015

10.12.2

Pinnacle West

APS

Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee

10.1 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473

1/20/1987

208

Table of Contents

~~10.12.2a~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.12.2a

Pinnacle West

APS

Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee

4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473

8/24/1987

10.12.2b

Pinnacle West

APS

Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee

10.4 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

10.12.2c

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Amendment No. 3, dated July 10, 2014, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to the First National Bank of Boston, as Lessor, and APS, as Lessee

10.2 to Pinnacle West/APS June 30, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473

7/31/2014

10.13.1

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Agreement between Pinnacle West Energy Corporation and APS for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th day of April, 2001

10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/16/2005

10.13.2

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001

10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/16/2005

~~Exhibit~~

~~No.~~

10.13.3

~~Registrant(s)~~Pinnacle West
APS

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~10.13.3~~

~~Pinnacle West~~

~~APS~~

Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP

10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/16/2005

10.13.4

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP

10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473

3/16/2005

10.13.5

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Municipal Effluent Purchase and Sale Agreement dated April 29, 2010, by and between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, City of Glendale, APS and SRP

10.1 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/6/2010

10.14.1

Pinnacle West

APS

Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP

10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386

3/13/1985

209

Table of Contents

~~10.15.1~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

10.15.1

Pinnacle West

APS

Territorial Agreement between APS and SRP

10.1 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473

5/15/1998

10.15.2

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Power Coordination Agreement between APS and SRP

10.2 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473

5/15/1998

10.15.3

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Memorandum of Agreement between APS and SRP

10.3 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473

5/15/1998

10.15.3a

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Addendum to Memorandum of Agreement between APS and SRP dated as of May 19, 1998

10.2 to APS’s May 19, 1998 Form 8-K Report, File No. 1-4473

6/26/1998

10.16

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Purchase and Sale Agreement dated November 8, 2010 by and between SCE and APS

10.1 to Pinnacle West/APS November 8, 2010 Form 8-K Report, File Nos. 1-8962 and 1-4473

11/8/2010

10.17

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Proposed Settlement Agreement dated January 6, 2012 by and among APS and certain parties to its retail rate case (approved by ACC Order No. 73183)

10.17 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473

2/24/2012

10.18

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

Proposed Settlement Agreement dated March 27, 2017 by and among APS and certain parties to its retail rate case (approved by ACC Order No. 76295)

10.1 to Pinnacle West/APS March 31, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473

5/2/2017

10.19

Pinnacle West

Purchase and Sale Agreement, dated June 29, 2018, by and between Navajo Transitional Energy Company, LLC and 4CA

10.2 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/3/2018

21.1

Pinnacle West

Subsidiaries of Pinnacle West

23.1

Pinnacle West

Consent of Deloitte & Touche LLP

23.2

APS

Consent of Deloitte & Touche LLP

31.1

Pinnacle West

Certificate of Jeffrey B. Guldner, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

~~Exhibit~~

~~No.~~

31.2

~~Registrant(s)~~Pinnacle West

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~31.2~~

~~Pinnacle West~~

Certificate of Theodore N. Geisler, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3

APS

Certificate of Jeffrey B. Guldner, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4

APS

Certificate of Theodore N. Geisler, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

210

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

32.1^e

Pinnacle West

Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2^e

APS

Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

~~99.1~~

~~Pinnacle West~~

~~APS~~

~~Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee~~

~~4.2 to APS’s 1992 Form 10-K Report, File No. 1-4473~~

~~3/30/1993~~

~~99.1a~~

~~Pinnacle West~~

~~APS~~

~~Supplemental Indenture to Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee~~

~~4.3 to APS’s 1992 Form 10-K Report, File No. 1-4473~~

~~3/30/1993~~

~~99.2~~99.1^c

Pinnacle West

APS

Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein

28.1 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473

11/9/1992

~~99.2a~~99.1a^c

Pinnacle West

APS

Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein

10.8 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473

12/4/1986

~~Exhibit~~

~~No.~~

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ 99.1bac

~~Date Filed~~

~~99.2b~~^c

Pinnacle West

APS

Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., PVGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein

28.4 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.3~~99.2^c

Pinnacle West

APS

Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee

4.5 to APS’s Form 18 Registration Statement, File No. 33-9480

10/24/1986

211

Table of Contents

Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

~~99.3a~~99.2a^c

Pinnacle West

APS

Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee

10.6 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473

12/4/1986

~~99.3b~~99.2b^c

Pinnacle West

APS

Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee

4.4 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.4~~99.3^c

Pinnacle West

APS

Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee

28.3 to APS’s Form 18 Registration Statement, File No. 33-9480

10/24/1986

~~99.4a~~99.3a^c

Pinnacle West

APS

Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee

10.10 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473

12/4/1986

~~Exhibit~~

~~No.~~

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ 99.3bac

~~Date Filed~~

~~99.4b~~^c

Pinnacle West

APS

Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee

28.6 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.5~~99.4

Pinnacle West

APS

Participation Agreement, dated as of December 15, 1986, among PVGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein

28.2 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473

11/9/1992

212

Table of Contents

~~99.5a~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

99.4a

Pinnacle West

APS

Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein

28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473

8/10/1987

~~99.5b~~99.4b

Pinnacle West

APS

Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVGS Funding Corp., Inc., PVGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein

28.5 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.6~~99.5

Pinnacle West

APS

Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee

10.2 to APS’s November 18, 1986 Form 10-K Report, File No. 1-4473

1/20/1987

~~99.6a~~99.5a

Pinnacle West

APS

Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee

4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473

8/24/1987

~~Exhibit~~

~~No.~~

99.5b

~~Registrant(s)~~

~~Description~~

~~Previously Filed as Exhibit:~~ a

~~Date Filed~~

~~99.6b~~

Pinnacle West

APS

Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee

4.5 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.7~~99.6

Pinnacle West

APS

Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee

10.5 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473

1/20/1987

213

Table of Contents

~~99.7a~~Exhibit
No.

Registrant(s)

Description

Previously Filed as Exhibit: a

Date Filed

99.6a

Pinnacle West

APS

Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee

28.7 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.8~~99.7^c

Pinnacle West

APS

Indemnity Agreement dated as of March 17, 1993 by APS

28.3 to APS’s 1992 Form 10-K Report, File No. 1-4473

3/30/1993

~~99.9~~99.8

Pinnacle West

APS

Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank

28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473

8/10/1987

~~99.10~~99.9

Pinnacle West
APS

~~Pinnacle West~~

~~APS~~

ACC Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules

10.2 to APS’s September 30, 1999 Form 10-Q Report, File No. 1-4473

11/15/1999

~~99.11~~99.10

Pinnacle West

Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005

99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473

8/9/2005

101.SCH

Pinnacle West

APS

XBRL Taxonomy Extension Schema Document

101.CAL

Pinnacle West

APS

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

Pinnacle West

APS

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Pinnacle West

APS

XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF

Pinnacle West

APS

XBRL Taxonomy Definition Linkbase Document

aReports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.

bManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.

cAn additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.

dAdditional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

eFurnished herewith as an Exhibit.

214

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		PINNACLE WEST CAPITAL CORPORATION
		(Registrant)


		~~PINNACLE WEST CAPITAL CORPORATION~~
	~~(Registrant)~~


Date: February ~~21, 2020~~24, 2021	/s/ Jeffrey B. Guldner
		(Jeffrey B. Guldner, Chairman of the Board of Directors, President and Chief Executive Officer)

Power of Attorney

We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Theodore N. Geisler and Robert E. Smith, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

~~Signature~~

~~Title~~

~~Date~~

/s/ Jeffrey B. Guldner

Principal Executive Officer

February ~~21, 2020~~24, 2021

(Jeffrey B. Guldner, Chairman

and Director

of the Board of Directors, President

and Chief Executive Officer)

~~/s/ Theodore N. Geisler~~

~~Principal Financial Officer~~

~~February 21, 2020~~

~~(Theodore N. Geisler,~~

~~Senior Vice President and~~

~~Chief Financial Officer)~~

~~/s/ Elizabeth A. Blankenship~~

~~Principal Accounting Officer~~

~~February 21, 2020~~

~~(Elizabeth A. Blankenship,~~

~~Vice President, Controller and~~

~~Chief Accounting Officer)~~

/s/ Theodore N. Geisler

Principal Financial Officer

February 24, 2021

(Theodore N. Geisler,

Senior Vice President and

Chief Financial Officer)

/s/ Elizabeth A. Blankenship

Principal Accounting Officer

February 24, 2021

(Elizabeth A. Blankenship,

Vice President, Controller and

Chief Accounting Officer)

215

Table of Contents

/s/ Glynis A. Bryan

Director

February 24, 2021

(Glynis A. Bryan)

/s/ Denis A. Cortese, M.D.

Director

February ~~21, 2020~~24, 2021

(Denis A. Cortese, M.D.)

/s/ Richard P. Fox

Director

February ~~21, 2020~~24, 2021

(Richard P. Fox)

~~/s/ Michael L. Gallagher~~

~~Director~~

~~February 21, 2020~~

~~(Michael L. Gallagher)~~

/s/ Dale E. Klein, Ph.D.

Director

February ~~21, 2020~~24, 2021

(Dale E. Klein, Ph.D.)

/s/ Humberto S. Lopez

Director

February ~~21, 2020~~24, 2021

(Humberto S. Lopez)

/s/ Kathryn L. Munro

Director

February ~~21, 2020~~24, 2021

(Kathryn L. Munro)

/s/ Bruce J. Nordstrom

Director

February ~~21, 2020~~24, 2021

(Bruce J. Nordstrom)

/s/ Paula J. Sims

Director

February ~~21, 2020~~24, 2021

(Paula J. Sims)

/s/ James E. Trevathan

Director

February ~~21, 2020~~24, 2021

(James E. Trevathan)

/s/ David P. Wagener

Director

February ~~21, 2020~~24, 2021

(David P. Wagener)

216

Table of Contents

SIGNATURES



			ARIZONA PUBLIC SERVICE COMPANY
			(Registrant)


Date: February ~~21, 2020~~24, 2021			/s/ Jeffrey B. Guldner
			(Jeffrey B. Guldner, Chairman of the Board of Directors and Chief Executive Officer)

Power of Attorney

We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Theodore N. Geisler and Robert E. Smith, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Signature

Title

Date

/s/ Jeffrey B. Guldner

Principal Executive Officer

February 24, 2021

(Jeffrey B. Guldner, Chairman

and Director

of the Board of Directors and

Chief Executive Officer)

/s/ Theodore N. Geisler

Principal Financial Officer

February 24, 2021

(Theodore N. Geisler,

Senior Vice President and

Chief Financial Officer)

/s/ Elizabeth A. Blankenship

Principal Accounting Officer

February 24, 2021

(Elizabeth A. Blankenship

Vice President, Controller and

Chief Accounting Officer)

217

Table of Contents

~~Signature~~/s/ Glynis A. Bryan

~~Title~~Director

~~Date~~February 24, 2021

(Glynis A. Bryan)

~~/s/ Jeffrey B. Guldner~~

~~Principal Executive Officer~~

~~February 21, 2020~~

~~(Jeffrey B. Guldner, Chairman~~

~~and Director~~

~~of the Board of Directors and~~

~~Chief Executive Officer)~~

~~/s/ Theodore N. Geisler~~

~~Principal Financial Officer~~

~~February 21, 2020~~

~~(Theodore N. Geisler,~~

~~Senior Vice President and~~

~~Chief Financial Officer)~~

~~/s/ Elizabeth A. Blankenship~~

~~Principal Accounting Officer~~

~~February 21, 2020~~

~~(Elizabeth A. Blankenship~~

~~Vice President, Controller and~~

~~Chief Accounting Officer)~~

/s/ Denis A. Cortese, M.D.

Director

February ~~21, 2020~~24, 2021

(Denis A. Cortese, M.D.)

/s/ Richard P. Fox

Director

February ~~21, 2020~~24, 2021

(Richard P. Fox)

~~/s/ Michael L. Gallagher~~

~~Director~~

~~February 21, 2020~~

~~(Michael L. Gallagher)~~

/s/ Dale E. Klein, Ph.D.

Director

February ~~21, 2020~~24, 2021

(Dale E. Klein, Ph.D.)

/s/ Humberto S. Lopez

Director

February ~~21, 2020~~24, 2021

(Humberto S. Lopez)

/s/ Kathryn L. Munro

Director

February ~~21, 2020~~24, 2021

(Kathryn L. Munro)

/s/ Bruce J. Nordstrom

Director

February ~~21, 2020~~24, 2021

(Bruce J. Nordstrom)

/s/ Paula J. Sims

Director

February ~~21, 2020~~24, 2021

(Paula J. Sims)

/s/ James E. Trevathan

Director

February ~~21, 2020~~24, 2021

(James E. Trevathan)

/s/ David P. Wagener

Director

February ~~21, 2020~~24, 2021

(David P. Wagener)

~~209~~

218



Commission File Number	Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address; and Telephone Number			IRS Employer Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION			86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix	Arizona	85072-3999
	(602)	250-1000
1-4473	ARIZONA PUBLIC SERVICE COMPANY			86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix	Arizona	85072-3999
	(602)	250-1000



PINNACLE WEST CAPITAL CORPORATION	$	10,536,165,750	as of June 30, 2019
ARIZONA PUBLIC SERVICE COMPANY	$	0	as of June 30, 2019


PINNACLE WEST CAPITAL CORPORATION	$	8,231,813,171	as of June 30, 2020
ARIZONA PUBLIC SERVICE COMPANY	$	0	as of June 30, 2020



				Page

GLOSSARY OF NAMES AND TECHNICAL TERMS				ii

FORWARD-LOOKING STATEMENTS				1

PART I				3
Item 1.			Business	3
Item 1A.			Risk Factors	2832
Item 1B.			Unresolved Staff Comments	4246
Item 2.			Properties	4347
Item 3.			Legal Proceedings	4650
Item 4.			Mine Safety Disclosures	4650
Information about our Executive Officers				4751

PART II				4852
Item 5.			Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4852
Item 6.7.			~~Selected Financial Data~~	49
~~Item 7.~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5153
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk	7482
Item 8.			Financial Statements and Supplementary Data	7583
			Pinnacle West Financial Statements	8189
			APS Financial Statements	90100
			Combined Notes to Consolidated Financial Statements	96106




















			Pinnacle West Schedule I	188
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~180~~192
Item 9A.			Controls and Procedures	~~180~~192
Item 9B.			Other Information	~~181~~193

PART III				~~181~~193
Item 10.			Directors, Executive Officers and Corporate Governance of Pinnacle West	~~181~~193
Item 11.			Executive Compensation	~~181~~193
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~182~~193
Item 13.			Certain Relationships and Related Transactions, and Director Independence	~~183~~193
Item 14.			Principal Accountant Fees and Services	~~184~~194

PART IV				~~185~~195
Item 15.			Exhibits and Financial Statement Schedules	~~185~~195

SIGNATURES				~~206~~215



		Page

Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)		7684
Report of Independent Registered Public Accounting Firm		7785
Pinnacle West Consolidated Statements of Income for 2020, 2019 ~~2018~~ and ~~2017~~2018		8189
Pinnacle West Consolidated Statements of Comprehensive Income for 2020, 2019 ~~2018~~ and ~~2017~~2018		8290
Pinnacle West Consolidated Balance Sheets as of December 31, ~~2019~~2020 and ~~2018~~2019		8391
Pinnacle West Consolidated Statements of Cash Flows for 2020, 2019 ~~2018~~ and ~~2017~~2018		8593
Pinnacle West Consolidated Statements of Changes in Equity for 2020, 2019 ~~2018~~ and ~~2017~~2018		8694

Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)		8795
Report of Independent Registered Public Accounting Firm		8896
APS Consolidated Statements of Income for 2020, 2019 ~~2018~~ and ~~2017~~2018		90100
APS Consolidated Statements of Comprehensive Income for 2020, 2019 ~~2018~~ and ~~2017~~2018		91101
APS Consolidated Balance Sheets as of December 31, ~~2019~~2020 and ~~2018~~2019		92102
APS Consolidated Statements of Cash Flows for 2020, 2019 ~~2018~~ and ~~2017~~2018		94104
APS Consolidated Statements of Changes in Equity for 2020, 2019 ~~2018~~ and ~~2017~~2018		95105

Combined Notes to Consolidated Financial Statements		96106



Note 1. Summary of Significant Accounting Policies		96106
Note 2. Revenue		~~103~~115
Note 3. New Accounting Standards		~~105~~117
Note 4. Regulatory Matters		~~106~~118
Note 5. Income Taxes		~~123~~139
Note 6. Lines of Credit and Short-Term Borrowings		~~127~~143
Note 7. Long-Term Debt and Liquidity Matters		~~129~~144
Note 8. Retirement Plans and Other Postretirement Benefits		~~131~~147
Note 9. Leases		~~140~~156
Note 10. Jointly-Owned Facilities		~~144~~159
Note 11. Commitments and Contingencies		~~145~~160
Note 12. Asset Retirement Obligations		~~153~~168
Note 13. ~~Selected Quarterly Financial Data (Unaudited)~~Fair Value Measurements		~~154~~169
Note 14. ~~Fair Value Measurements~~Earnings Per Share		~~155~~175
Note 15. ~~Earnings Per Share~~Stock-Based Compensation		~~162~~175
Note 16. ~~Stock-Based Compensation~~Derivative Accounting		~~162~~178
Note 17. ~~Derivative Accounting~~		~~165~~
~~Note 18.~~ Other Income and Other Expense	~~169~~182
Note ~~19.~~18. Palo Verde Sale Leaseback Variable Interest Entities		~~170~~183
Note ~~20.~~19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds		~~171~~183
Note ~~21.~~20. Changes in Accumulated Other Comprehensive Loss		~~174~~187



PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of February ~~14, 2020:~~17, 2021:	~~112,439,441~~112,691,601
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of February ~~14, 2020:~~17, 2021:	71,264,947



4CA			4C Acquisition, LLC, a subsidiary of the Company
AC			Alternating Current
ACC			Arizona Corporation Commission
ADEQ			Arizona Department of Environmental Quality
AFUDC			Allowance for Funds Used During Construction
ANPP			Arizona Nuclear Power Project, also known as Palo Verde
APS			Arizona Public Service Company, a subsidiary of the Company
ARO			Asset retirement obligations
ASU			Accounting Standards Update
BART			Best available retrofit technology
Base Fuel Rate			The portion of APS’s retail base rates attributable to fuel and purchased power costs
BCE			Bright Canyon Energy Corporation, a subsidiary of the Company
CAISO			California Independent System Operator
CCR			Coal combustion residuals
Cholla			Cholla Power Plant
DCCOVID-19			~~Direct Current~~Coronavirus
DC			Direct Current
distributed energy systems			Small-scale renewable energy technologies that are located on customers’ properties, such as rooftop solar systems
DOE			United States Department of Energy
DOI			United States Department of the Interior
DSM			Demand side management
EES			Energy Efficiency Standard
EGU			Electric generating unit
El Dorado			El Dorado Investment Company, a subsidiary of the Company
El Paso			El Paso Electric Company
EPA			United States Environmental Protection Agency
FERC			United States Federal Energy Regulatory Commission
Four Corners			Four Corners Power Plant
GHG			Greenhouse gas
GWh			Gigawatt-hour, one billion watts per hour
kV			Kilovolt, one thousand volts
kWh			Kilowatt-hour, one thousand watts per hour
LFCR			Lost Fixed Cost Recovery Mechanism
MMBtu			One million British Thermal Units
MW			Megawatt, one million watts
MWh			Megawatt-hour, one million watts per hour
Native Load			Retail and wholesale sales supplied under traditional cost-based rate regulation
Navajo Plant			Navajo Generating Station
NERC			North American Electric Reliability Corporation
NRC			United States Nuclear Regulatory Commission
NTEC			Navajo Transitional Energy Company, LLC
OCI			Other comprehensive income
OSM			Office of Surface Mining Reclamation and Enforcement
Palo Verde			Palo Verde Generating Station or PVGS
Pinnacle West			Pinnacle West Capital Corporation (any use of the words “Company,” “we,” and “our” refer to Pinnacle West)
PSA			Power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
RES			Arizona Renewable Energy Standard and Tariff
Salt River Project or SRP			Salt River Project Agricultural Improvement and Power District
SCE			Southern California Edison Company
TCA			Transmission cost adjustor
TEAM			Tax expense adjustor mechanism
VIE			Variable interest entity


~~(d)~~	~~Unit 3 was retired in October 2019 with Units 1 and 2 following in November 2019.~~


~~(e)~~	~~Ocotillo Steam Units 1 and 2 were retired on January 10, 2019. Units 3 through 7 all went into service on or prior to May 30, 2019 which increased generation capacity by 510 MW.~~


~~(f)~~	~~Redhawk generation capacity increased by 104 MW following the Advanced Gas Path upgrade installed on both units.~~



	Percent Owned (Weighted-Average)
Morgan — Pinnacle Peak System	64.6	%
Palo Verde — Rudd 500kV System	50.0	%
Round Valley System	50.0	%
ANPP 500kV System	33.5	%
Navajo Southern System	~~26.7~~26.0	%
Four Corners Switchyards	~~63.0~~61.8	%
Palo Verde — Yuma 500kV System	~~19.0~~25.3	%
Phoenix — Mead System	17.1	%
Palo Verde — Morgan System	88.9	%
Hassayampa — North Gila System	80.0	%
Cholla 500kV Switchyard	85.7	%
Saguaro 500kV Switchyard	60.0	%
Kyrene -— Knox System	50.0	%



	2020		2021- 2022		2023- 2024		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	554	$	398	$	757	$	7,405	$	9,114
Pinnacle West	460		—		—		—		460
Total long-term debt payments, including interest	1,014		398		757		7,405		9,574
Short-term debt payments, including interest (b)	115		—		—		—		115
Fuel and purchased power commitments (c)	569		1,217		1,176		5,318		8,280
Renewable energy credits (d)	36		66		58		133		293
Purchase obligations (e)	21		20		21		196		258
Coal reclamation	17		33		37		88		175
Nuclear decommissioning funding requirements	2		4		4		50		60
Noncontrolling interests (f)	23		46		39		143		251
Operating lease payments (g)	15		20		10		39		84
Total contractual commitments	$	1,812	$	1,804	$	2,102	$	13,372	$	19,090


~~(a)~~	~~Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.~~



	Increase (Decrease)
Actuarial Assumption (a)	Impact on Other Postretirement Benefit Obligation			Impact on Other Postretirement Benefit Expense
Discount rate:
Increase 1%	$	(104	)	$	(1	)
Decrease 1%	134			5
Healthcare cost trend rate (b):
Increase 1%	124			9
Decrease 1%	(98		)	(4		)
Expected long-term rate of return on plan assets – pretax:
Increase 1%	—			(4		)
Decrease 1%	—			4


~~(b)~~	~~This assumes a 1% change in the initial and ultimate healthcare cost trend rate.~~



	December 31, 2019 Gain (Loss)					December 31, 2018 Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity	$	—	$	—		$	1	$	(1	)
Natural gas	55		(55		)	44		(44		)
Total	$	55	$	(55	)	$	45	$	(45	)


~~(a)~~	These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.