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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
 
(Mark One)
 
      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2020
 
OR
 
      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to             

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

 
Securities registered pursuant to Section 12(b) of the Act:
    Title Of Each Class   Trading Symbol Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION   Common Stock,
No Par Value
  PNW New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
ARIZONA PUBLIC SERVICE COMPANY             Common Stock, Par Value $2.50 per share
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
PINNACLE WEST CAPITAL CORPORATION Yes
 
No  ☐ 
ARIZONA PUBLIC SERVICE COMPANY Yes
 
No  ☐ 
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
PINNACLE WEST CAPITAL CORPORATION Yes
 
No ☐ 
ARIZONA PUBLIC SERVICE COMPANY Yes
 
No ☐ 
 
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
PINNACLE WEST CAPITAL CORPORATION Yes
 
No  ☐ 
ARIZONA PUBLIC SERVICE COMPANY Yes
 
No  ☐ 
 
    Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PINNACLE WEST CAPITAL CORPORATION Yes
 
No 
 
ARIZONA PUBLIC SERVICE COMPANY Yes
 
No 
 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer
 
Accelerated filer Non-accelerated filer Smaller reporting company
Emerging growth company
 
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer Accelerated filer Non-accelerated filer
 
Smaller reporting company
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PINNACLE WEST CAPITAL CORPORATION Yes   No 
 
ARIZONA PUBLIC SERVICE COMPANY Yes     No 
 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:
PINNACLE WEST CAPITAL CORPORATION   $ 8,231,813,171  as of June 30, 2020
ARIZONA PUBLIC SERVICE COMPANY   $ as of June 30, 2020
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
PINNACLE WEST CAPITAL CORPORATION Number of shares of common stock, no par value, outstanding as of February 17, 2021: 112,691,601
ARIZONA PUBLIC SERVICE COMPANY Number of shares of common stock, $2.50 par value, outstanding as of February 17, 2021: 71,264,947

 
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 19, 2021 are incorporated by reference into Part III hereof.
 
Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.




TABLE OF CONTENTS
 
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This combined Form 10-K is separately filed by Pinnacle West and APS.  Each registrant is filing on its own behalf all of the information contained in this Form 10-K that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Consolidated Financial Statements of APS.  Item 8 also includes Combined Notes to Consolidated Financial Statements.
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Table of Contents
GLOSSARY OF NAMES AND TECHNICAL TERMS
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
COVID-19 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
ii

Table of Contents
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,” “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 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 landowners to meet contractual or other obligations or extend the rights for continued power plant 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 6,321 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 2020, no single purchaser or user of energy accounted for more than 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.
PNW-20201231_G1.JPG

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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 2020 were as follows:
PNW-20201231_G2.JPG
*Renewables include energy from wind, solar, geothermal, biomass, distributed generation and solar power purchase agreements.

The share of APS’s energy supply being derived from clean resources is 50%. BCE also has acquired minority ownership positions in two wind farms that achieved commercial operation in 2020. Both wind farms deliver power under long-term power purchase agreements. See “Business of Other Subsidiaries — Bright Canyon Energy” below for information regarding BCE’s investment.

Clean Energy Focus Initiatives

APS has undertaken a number of initiatives to reduce carbon, including renewable energy procurement and development, and promotion of programs and rates that promote energy conservation, renewable energy use, and energy efficiency. (See “Energy Sources and Resource Planning — Current and Future Resources” below for details of these plans and initiatives.) APS currently has a diverse portfolio of renewable resources, including solar, wind, geothermal, biogas, and biomass. In addition, in January 2020 APS announced its Clean Energy Commitment, a three-pronged approach aimed at ultimately eliminating carbon-emitting resources from its electric generation resource portfolio.
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APS’s clean energy goals consist of three parts:
a 2050 goal to provide 100% clean, carbon-free electricity;
a 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and
a commitment to end APS’s use of coal-fired generation by 2031.

Among other strategies, APS intends to achieve these goals through various methods such as relying on Palo Verde, the nation’s largest producer of carbon-free energy; increasing clean energy resources, including renewables; developing energy storage; 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 Discussion and Analysis of Financial Condition and Results of Operation” for additional information about APS’s Clean Energy Commitment.)

Over this same period of time, APS also intends to harden its infrastructure in order to improve climate resiliency, which involves system and operational improvements aimed at reducing the impact of extreme weather events and other climate-related disruptions upon APS’s operations. Among other resiliency strategies, APS anticipates increasing investments in a modern and more flexible electricity grid with advanced distribution technologies. APS plans to continue its comprehensive forest management programs aimed at reducing wildfires, as those risks become compounded by shorter, drier winters and longer, hotter summers.

APS prepares an annual inventory of GHG emissions from its operations. For APS’s operations involving fossil-fuel electricity generation and electricity transmission and distribution, APS’s annual GHG inventory is reported to EPA under the EPA GHG Reporting Program. APS also voluntarily tracks the full scope of APS’s GHG emissions arising from all APS operations. In addition to GHG emissions from generation and transmission and distribution operations, this data includes all other GHG emissions arising from ancillary APS operations, such as vehicle use, employee travel, portable generators and facility energy usage. This data is then communicated to the public in Pinnacle West’s annual Corporate Responsibility Report, which is available on our website (www.pinnaclewest.com/corporate-responsibility). 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 Note 18 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 2027 and 70% through 2028; 100% of Palo Verde’s requirements for conversion services through 2030; 100% of Palo Verde’s requirements for enrichment services through 2026 and 40% for 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”) 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, 2022.

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

Waste Confidence and Continued Storage — On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel.  The petitioners had challenged the NRC’s 2010 update to the agency’s waste confidence decision and temporary storage rule (“Waste Confidence Decision”). The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with National Environmental Policy Act. In September 2013, the NRC issued its draft Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed as the Continued Storage Rule, the NRC’s decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continued Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
    
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in
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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 Note 19 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. A portion of the gas for these plants is financially hedged up to five years in advance of purchasing and that position is converted to a physical gas purchase one month prior to delivery. 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 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 Rate Case 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 interest in these units described below. As part of APS’s Clean Energy Commitment, APS has committed to cease using coal-fired generation as part of its portfolio of electricity generating resources, including Four Corners, by 2031.

NTEC, a company formed by the Navajo Nation to own the mine that serves Four Corners and develop other energy projects, is the coal supplier for Four Corners. The Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016 through 2031 (the “2016 Coal Supply Agreement”). El Paso, a 7% owner of Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS agreed to assume the 7% shortfall obligation. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso’s reclamation and decommissioning obligations associated with the 7% interest.

On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA’s 7% interest in Four Corners. 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 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.

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.
 
Cholla — Cholla was originally a 4-unit coal-fired power plant, which is located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4, and APS operated that unit for PacifiCorp. On September 11, 2014, APS announced that it would close Cholla Unit 2 and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the Unit. APS closed
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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 compromise proposal, which took effect for Cholla on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020.

APS 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 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 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 allowed for decommissioning activities to begin after the plant ceased operations in November 2019.

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant (see Note 4 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material.

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

In the 2017 Rate Case Decision, the ACC also approved the “APS Solar Communities” program. APS Solar Communities (formerly AZ Sun II) is a three-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned 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 9 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, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional energy storage in the future.

In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under the agreement was scheduled to begin in 2021; however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date. In 2018, APS issued a request for proposal ("RFP") for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. These battery storage facilities are expected to be in service by June 2022. Additionally, in February 2019, APS signed two 20-year power purchase agreements (“PPAs”) for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. APS has now completed its investigation of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs. These PPAs were also subject to ACC approval in order to allow for cost recovery through the PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

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We currently plan to install at least 850 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites that were not included in the 2018 RFP referenced in the preceding paragraph; and (ii) an ‘all source’ RFP that solicits both standalone energy storage and renewable energy plus energy storage resources. Such resources would be expected to be in service during 2023 and 2024.

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 16.)  APS continually assesses its need for additional capacity resources to assure system reliability. In addition, APS has also entered into several power purchase agreements for energy storage. (See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for details of our energy storage power purchase agreements.)

Purchased Power Capacity — APS’s purchased power capacity under long-term contracts as of December 31, 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, 2022   45 
Exchange Agreement (b)   May 15 to September 15 annually through February 2021   480 
Demand Response Agreement (c)   Summer seasons through 2025   75 
Tolling Agreement Summer seasons from Summer 2020 through Summer 2025 565 
Tolling Agreement June 1 through September 30, 2020-2026 570 
Renewable Energy (d)   Various   626 
Tolling Agreement May 1 through October 31, 2021-2027 463 
(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 2020 peak one-hour demand on its electric system was recorded on July 30, 2020 at 7,660 MW, compared to the 2019 peak of 7,115 MW recorded on August 5, 2019.  APS’s reserve margin at the time of the 2020 peak demand, calculated using system load serving capacity, was 19%.  For 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 15-year Integrated Resource Plans (“IRP”) which describe how the utility plans to serve customer load in the plan timeframe.  The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged.  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 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 of Arizona Public Service Company — Energy Sources and Resource Planning — Clean Energy Focus Initiatives” and “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for information regarding future plans for energy storage. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities” above for information regarding plans for Cholla, Four Corners and the Navajo Plant.

Energy Imbalance Market

In 2015, APS and the CAISO, the operator for the majority of California’s transmission grid, signed an agreement for APS to begin participation in the Energy Imbalance Market (“EIM”). APS’s participation in the EIM began on October 1, 2016.  The EIM allows for rebalancing supply and demand in 15-minute blocks, with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks. Participation in the EIM continues to be an effective tool for creating savings for APS’s customers from the real-time, voluntary market. APS continues to expect that its participation in EIM will lower its fuel and purchased-power costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources. 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 11% of retail electric sales in 2021 and increases annually until it reaches 15% in 2025. 
    
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 11% in 2021. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan. On July 1, 2020, APS filed its 2021 RES Implementation Plan. The following table summarizes the RES requirement standard 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%

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.

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Renewable Energy Portfolio.  To date, APS has a diverse portfolio of existing and planned renewable resources totaling 2,106 MW, including solar, wind, geothermal, biomass and biogas.  Of this portfolio, 1,956 MW are currently in operation and 150 MW are under contract for development or are under construction.  Renewable resources in operation include 245 MW of facilities owned by APS, 626 MW of long-term purchased power agreements, and an estimated 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 Sources and Resource Planning — Generation Facilities — Solar 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, 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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(a)Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.
(b)Includes 90 MW wind power purchase agreement that was in operation until 2021. As a result of a power purchase agreement executed in September 2020, this will be decommissioned in 2021 and rebuilt in the same year, together with an additional 110 MW, for a total of 200 MW.
(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

On January 1, 2011, Arizona regulators adopted an EES of 22% cumulative annual energy savings by 2020 to increase energy efficiency and other demand side management programs encouraging customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. APS achieved the 22% EES in 2020. (See Note 4 for information regarding energy efficiency, other DSM obligations and the Energy Modernization Plan.)

Competitive Environment and Regulatory Oversight
 
Retail
 
The ACC regulates APS’s retail electric rates and its issuance of securities.  The ACC must also approve any significant transfer or encumbrance of APS’s property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates. (See Note 4 for information regarding ACC’s regulation of APS’s retail electric rates.)
 
APS is subject to varying degrees of competition from other investor-owned electric and gas utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations.  In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet some or all of their own energy requirements.  This practice is becoming more popular with customers installing or having installed products such as rooftop solar panels to meet or supplement their energy needs.
 
On 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.

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore the retail electric competition rules. 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 2020, approximately 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 natural gas.  The majority of these activities are undertaken to mitigate risk in APS’s portfolio.

Transmission and Delivery 

APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and clean energy development.  The capital expenditures table presented in the “Liquidity and Capital Resources” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations 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

Legislative Initiatives. There have been no recent successful attempts by Congress to pass legislation that would regulate GHG emissions, and it is unclear at this time whether climate-change related legislation originating from the 117th Congress will be considered in the Senate and then signed into law by President Biden. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is written, enacted, and the specifics of the resulting program are established. These factors include the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”) equivalent emitted.

In addition to federal legislative initiatives, state-specific initiatives may also impact our business. While Arizona has no pending legislation 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”) analysis for new major sources and major modifications to existing plants.

On June 19, 2019, EPA took final action on its proposals to repeal EPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

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

Cholla. In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements. In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025. PacifiCorp retired Cholla Unit 4 at the end of 2020. (See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.)
    
Four Corners. Based on EPA’s final standards, APS’s 63% share of the cost of required BART controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred.  (See Note 4 for information regarding the related rate recovery.) In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC purchased the interest from 4CA on July 3, 2018. (See “Four Corners — 4CA Matter” in Note 11 for a discussion of the NTEC purchase.) The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

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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 July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments; such disposal units must close as soon as technically feasible, but no later than April 22, 2021.
On 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 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 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 on November 30, 2020 and is currently pending. This application will be subject to 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 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 $27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was 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 have ceased operating and initiated closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. 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. 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 October 13, 2020, EPA published a final rule relaxing these “zero discharge” limitations for bottom ash handling water and allowing for approximately 10% of such wastewater to be discharged (on a volumetric, 30-day rolling average basis) under limited power plant operating scenarios. At this time, APS is pursuing a modification to the Four Corners NPDES discharge permit in order to implement the most recent ELG rulemaking. We cannot at this time predict the outcome of this permit modification proceeding, including any public commenting or permit appeal procedures. The Cholla facility does not require NPDES permitting.

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 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 natural gas-fired EGUs are located in these jurisdictions. Areas of Arizona and the Navajo Nation where the remainder of APS’s fossil-fuel fired EGU fleet is located were designated as in attainment. 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” or “Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time, expenditures related to this matter cannot be reasonably estimated.

On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  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 exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file
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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.

Four Corners National Pollutant Discharge Elimination System Permit

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board (“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised 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. Based upon a November 1, 2019 filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit. Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. 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 these appeal proceedings and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

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. No trial or pretrial proceedings have been scheduled for adjudication of APS’s water right claims. The adjudication court is currently conducting a trial of federal reserved water right claims asserted by the Hopi Tribe and by the United States as trustee for the Tribe. In addition, the adjudication court has established a schedule for consideration of separate federal reserved water right claims asserted by the Navajo Nation and by the United States as trustee for the Nation. There is no established timeframe within which the adjudication court is expected to issue a final determination of water rights for the Hopi Tribe and the Navajo Nation and any such final determination is likely to occur multiple years in the future.

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

BUSINESS OF OTHER SUBSIDIARIES

Bright Canyon Energy

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.  BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry.  In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates. As of December 31, 2020, BCE had total assets of approximately $27 million.

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

El Dorado
 
El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures.  El Dorado’s short-term goal is to prudently realize the value of its existing investments.  As of December 31, 2020, El Dorado had total assets of approximately $16 million. El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.

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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, 2020
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 5,933 
BCE 400 East Van Buren
Phoenix, AZ 85004
2014
El Dorado 400 East Van Buren
Phoenix, AZ 85004
1983 — 
4CA 400 North Fifth Street
Phoenix, AZ 85004
2016 — 
Total     6,026 
 
The APS number includes employees at jointly-owned generating facilities (approximately 2,304 employees) for which APS serves as the generating facility manager.  Approximately 1,263 APS employees are union employees, represented by the International Brotherhood of Electrical Workers (“IBEW”). In March 2020, the Company concluded negotiations with the IBEW and approved a three-year extension of the contract set to expire on April 1, 2020.  Under the extension, union members received wage increases for 2020, 2021 and 2022; there were no other changes. The current contract expires on April 1, 2023.

Human Capital

The Company seeks to attract the best employees, to retain those employees and to create a safe, inclusive and productive work environment for all employees. We believe the strength of our employees is one of the significant contributors to our Company’s success. Human capital measures and objectives that the Company focuses on in managing its business include the safety of its employees, diversity and inclusion, succession planning, hiring and retention of talent, compensation and benefits and employee engagement.

COVID-19

The health, well-being and safety of our employees, customers and communities is our top priority. In March 2020, we began operating under our long-standing pandemic and business continuity plans to address COVID-19. We had regular COVID-19 planning sessions to address the safety, operational and business risks associated with the pandemic. By the middle of March 2020, we successfully transitioned all of our employees to remote work unless they were essential workers that needed to remain onsite. These efforts have resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations. We also established COVID-19 safety protocols, social distancing practices including limiting one employee per vehicle and offering virtual options whenever possible. 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
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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.

Employee Safety

Our work and our decisions are anchored in safety – safety is the foundation of everything we do, and employee safety is our paramount responsibility as an employer. We develop safety practices and programs that ensure employees have safe and secure workplaces that allow them to perform at the highest levels. Our comprehensive safety programs and our focus on human and organizational performance and injury case management contribute significantly to our strong safety performance. As we continue to improve our safety performance, our ultimate goal remains serious injury reduction. Our employees are expected to do the right thing and empowered to speak up when there are better or safer ways of doing business, including stopping work to reassess or improve safety. Safety committees operate in organizations throughout the Company, providing opportunities for employees to positively impact their local safety cultures and performance.

Diversity, Equity and Inclusion

Diversity, equity and inclusion are core cultural principles, and we recognize that diversity of demographics, backgrounds and cultural perspective is a key driver for our success. Our Executive Diversity & Inclusion Council leads this commitment with an emphasis on diversity among employees, in the workplace and through our community involvement, as well as an increased focus on attracting and retaining diverse talent. This focus extends to individual business units in the Company, which report on the diversity of their team during management review meetings to build awareness and address gaps of workforce diversity. Our efforts to support and empower employees include a commitment to full inclusion. In 2019, we signed the UNITY Pledge in support of full inclusion and equality in employment, housing and public accommodations for all Arizonans, including gay and transgender people. The UNITY Pledge reinforces our commitment to fostering an environment that recognizes our employees’ unique needs and celebrates the value of diverse perspectives. The Company sponsors ten employee network groups that are intended to create a sense of inclusion and belonging for employees. In 2020, we conducted company-wide executive listening sessions to provide our employees with the opportunity to share their inclusion experiences with our officers. We continue to focus on hiring diverse employees as well as hiring employees from our veteran community. At the end of 2020, 36% of external hires were ethnically diverse, 36% were female and 18% were veterans. Additionally, as of December 31, 2020, 32% of our employees are ethnically or racially diverse, 24% are female and 17% are veterans.

Succession Planning

Through a strong focus on succession planning, we ensure that our Company is prepared to fill executive and other key leadership roles with capable, experienced employees. We continually revisit and revise succession plans to make certain that qualified individuals are in place to move into critical positions. We have strategically selected successors for our management team to lead our Company into the future with strong and sustainable performance. In addition, we assure that each business unit of the Company has talent management strategies and development plans to meet its future leadership needs. Effective succession planning helps us identify employees with leadership potential and also allows us to evaluate any gaps in education, skills and experience that need to be addressed to prepare those employees to move into leadership roles. At management review meetings, officers and directors review how business units are addressing succession planning, leadership opportunities and retirement projections.
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Talent Strategy

We place significant focus on attracting and developing a skilled workforce. To attract and retain top talent, we provide formal professional development programs through blended learning education and leadership training. Our employees have access to a wide variety of training and development opportunities, including leadership academies, rotational programs, mentoring programs, industry certifications and loaned executive programs. Talent pipelines help sustain our skilled workforce needs. Pipeline strategies include our apprentice and rotational programs. Additionally, our recruiters target specific colleges and programs of study that we have identified as talent pipelines. In 2020, we hosted 56 summer interns from 11 different universities 100% virtually with a diversity rate of 52%.

Total Rewards Strategy

In addition to our talent strategy, we place significant focus on our Total Rewards strategy for attracting, developing and rewarding our highly skilled workforce. Our employees are important to the success and future of our organization and our customers’ experiences. At the Company, our pay and benefits, along with retirement, recognition, time off, career development and wellbeing, make up our Total Rewards program. It is an important part of the employee experience at the Company and supports personal wellbeing and professional satisfaction. We are committed to providing programs that matter to our employees throughout various life and career phases.

Employee Engagement

An annual employee experience survey and focused quarterly pulse-surveys, enable us to gather employee feedback, identify opportunities for improvement and compare our performance to other companies. Through the surveys, we track our Employee Experience Index, a set of seven questions that encompass key elements of a positive employee experience, including recognition, career development possibilities and pride in the organization. Based on survey results, business units and individual managers are encouraged to take meaningful actions to improve the employee experience. In response to past surveys, we have launched enterprise-wide initiatives focused on improving communication between employees and management as well as removing obstacles that prevent job success. Other initiatives driven by the survey have given employees more access to leadership and improved meeting efficiency. Our cross-functional Employee Engagement Council focuses on improving employee recognition across the organization. We work to ensure that a positive work environment is maintained for all employees. Through an outreach initiative, we obtain feedback from new hires regarding their employee experience. In 2019, we integrated our employee experience surveys with onboarding surveys and exit interviews. Bringing together these elements allows us to get a more complete picture of the experience of our employees, from the time they join the Company until they decide to leave.

Company Culture

In 2020, the Company launched the APS Promise, anchoring our commitment to our customers, community, and each other. The Promise explains our purpose, our vision and mission and the principles and behaviors that will empower us to achieve our strategic goals. It represents the opportunity to build on our cultural strengths and develop new behaviors to enable our future success.



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WHERE TO FIND MORE INFORMATION

We use our website (www.pinnaclewest.com) as a channel of distribution for material Company information.  The following filings are available free of charge on our website as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”):  Annual Reports on Form 10-K, definitive proxy statements for our annual shareholder meetings, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports. The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, such as the Company, that file electronically with the SEC. The address of that website is www.sec.gov. Our board and committee charters, Code of Ethics for Financial Executives, Code of Ethics and Business Practices and other corporate governance information is also available on the Pinnacle West website.  Pinnacle West will post any amendments to the Code of Ethics for Financial Executives and Code of Ethics and Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its website.  The information on Pinnacle West’s website is not incorporated by reference into this report.
 
You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address:  Pinnacle West Capital Corporation, Office of the Corporate Secretary, Mail Station 8602, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-4400).

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ITEM 1A.  RISK FACTORS 

In addition to the factors affecting specific business operations identified in the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results.  Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.
REGULATORY RISKS
Our financial condition depends upon APS’s ability to recover costs in a timely manner from customers through regulated rates and otherwise execute its business strategy.
APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business, liquidity and results of operations and its ability to fully recover costs from utility customers in a timely manner.  The ACC regulates APS’s retail electric rates and FERC regulates rates for wholesale power sales and transmission services.  The profitability of APS is affected by the rates it may charge and the timeliness of recovering costs incurred through its rates and adjustor recovery mechanisms. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of any APS rate proceedings, adjustor recovery and ancillary matters which may come before the ACC and FERC, including in some cases how court challenges to these regulatory decisions are resolved. Arizona, like certain other states, has a statute that allows the ACC to reopen prior decisions and modify otherwise final orders under certain circumstances. Additionally, given that APS is subject to oversight by several regulatory agencies, a resolution by one may not foreclose potential actions by others for similar or related matters, such as the recent resolution of an Arizona Attorney General matter (see Note 11).
The ACC must also approve APS’s issuance of equity and debt securities and any significant transfer or encumbrance of APS property used to provide retail electric service, and must approve or receive prior notification of certain transactions between us, APS and our respective affiliates, including the infusion of equity into APS.  Decisions made by the ACC or FERC could have a material adverse impact on our financial condition, results of operations or cash flows.
APS’s ability to conduct its business operations and avoid negative operational and financial impacts depends in part upon compliance with federal, state and local statutes, regulations and ACC requirements, which may be revised from time to time by legislative or other action, and obtaining and maintaining certain regulatory permits, approvals and certificates.
APS must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of agencies that regulate APS’s business, including FERC, NRC, EPA, the ACC, and state and local governmental agencies.  These agencies regulate many aspects of APS’s utility operations, including safety and performance, emissions, siting and construction of facilities, customer service and the rates that APS can charge retail and wholesale customers.  Failure to comply can subject APS to, among other things, fines and penalties.  For example, under the Energy Policy Act of 2005, FERC can impose penalties (approximately $1.2 million dollars per day per violation) for failure to comply with mandatory electric reliability standards.  APS is also required to have numerous permits, approvals and certificates from these agencies.  APS believes the necessary permits, approvals and certificates have been obtained for its existing operations and that APS’s business is conducted in accordance with applicable laws in all material respects. 
Changes in laws or regulations that govern APS, new interpretations of law and regulations, or the imposition of new or revised laws or regulations could have an adverse impact on the manner in which we operate our business and our results of operations. In particular, new or revised laws or interpretations of existing laws or regulations may impact or call into question the ACC’s permissive regulatory authority,
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which may result in uncertainty as to jurisdictional authority within our state, and uncertainty as to whether ACC decisions will be binding or challenged by other agencies or bodies asserting jurisdiction. We are unable to predict the impact on our business and operating results from any pending or future regulatory or legislative rulemaking.
The operation of APS’s nuclear power plant exposes it to substantial regulatory oversight and potentially significant liabilities and capital expenditures.
The NRC has broad authority under federal law to impose safety-related, security-related and other licensing requirements for the operation of nuclear generating facilities.  Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generating facilities, including Palo Verde.  In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increased inspection regime that could ultimately result in the shut-down of a unit or civil penalties, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved.  The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect APS’s financial condition, results of operations and cash flows.
APS is subject to numerous environmental laws and regulations, and changes in, or liabilities under, existing or new laws or regulations may increase APS’s cost of operations or impact its business plans.
APS is, or may become, subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of conventional pollutants and greenhouse gases, water quality, discharges of wastewater and waste streams originating from fly ash and bottom ash handling facilities, solid waste, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash, and air pollution control wastes.  These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations.  These laws and regulations generally require APS to obtain and comply with a wide variety of environmental licenses, permits, and other approvals.  If there is a delay or failure to obtain any required environmental regulatory approval, or if APS fails to obtain, maintain, or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses.  In addition, failure to comply with applicable environmental laws and regulations could result in civil liability as a result of government enforcement actions or private claims or criminal penalties.  Both public officials and private individuals may seek to enforce applicable environmental laws and regulations.  APS cannot predict the outcome (financial or operational) of any related litigation that may arise.
Environmental Clean Up.  APS has been named as a PRP for a Superfund site in Phoenix, Arizona, and it could be named a PRP in the future for other environmental clean-up at sites identified by a regulatory body. APS cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs.  There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs.
Coal Ash. In December 2014, EPA issued final regulations governing the handling and disposal of CCR, which are generated as a result of burning coal and consist of, among other things, fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. To the extent the rule requires the closure or modification of these CCR units or the construction of new CCR units beyond what we currently anticipate, APS would incur significant additional costs for CCR disposal. In addition, the rule may also require corrective action to address releases from CCR disposal units or the presence of CCR constituents within groundwater near CCR disposal units above certain regulatory thresholds.
Ozone National Ambient Air Quality Standards. In 2015, EPA finalized revisions to the national ambient air quality standards for nitrogen oxides, which set new, more stringent standards intended to
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protect human health and human welfare. Depending on the final attainment designations for the new standards and the state implementation requirements, APS may be required to invest in new pollution control technologies and to generate emission offsets for new projects or facility expansions located in ozone nonattainment areas.
APS cannot assure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to it.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’s customers, could have a material adverse effect on its financial condition, results of operations or cash flows.  Due to current or potential future regulations or legislation coupled with trends in natural gas and coal prices, or other clean energy rules or initiatives, the economics or feasibility of continuing to own certain resources, particularly coal facilities, 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.
APS faces potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG emissions, as well as physical and operational risks related to climate effects.
Concern over climate change has led to significant legislative and regulatory efforts to limit CO2, which is a major byproduct of the combustion of fossil fuel, and other GHG emissions.
Potential Financial Risks — Greenhouse Gas Regulation, the Clean Power Plan and Potential Litigation. In 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants, the CPP. The implementation of this rule within the jurisdictions where APS operates would have resulted in a shift in generation from coal to more natural gas and renewable generation. Because of a view that the federal Clean Air Act did not permit such an expansive use of administrative authority over utility generation resources, in 2019 regulations were issued that repealed the CPP and replaced it with a far narrower set of regulations focused solely on coal-fired power plant efficiency improvements. On January  19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to EPA to develop new regulations governing carbon emissions from existing power plants consistent with the court’s ruling. That decision endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP, and the current administration has expressed its intent to assert such authority through new carbon emission regulations governing existing power plants.
Depending on the outcome of future carbon emission rulemakings under the Clean Air Act targeting new and existing power plants, the utility industry may become subject to more stringent and expansive regulations. To the extent that these regulations focus on generation shifting as a means of compliance with federal emission performance standards, the electric utility industry may be forced to incur substantial costs necessary to achieve compliance. In addition, we anticipate that such regulations will be challenged in federal court prior to their implementation. Depending on the outcome of such judicial review, the utility industry may face alternative efforts from private parties seeking to establish alternative GHG emission limitations from power plants. Alternative GHG emission limitations may arise from litigation under either federal or state common laws or citizen suit provisions of federal environmental statutes that attempt to force federal agency rulemaking or imposing direct facility emission limitations. Such lawsuits may also seek damages from harm alleged to have resulted from power plant GHG emissions.
Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the southwest United States’ desert area, and these are risks that APS considers in the normal course of business in the engineering and construction of its electric system.
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Large increases in ambient temperatures could require evaluation of certain materials used within its system and may represent a greater challenge. As part of conducting its business, APS recognizes that the southwestern United States is particularly susceptible to the risks posed by climate change, which over time is projected to exacerbate high temperature extremes and prolong drought in the area where APS conducts its business.
Co-owners of our jointly owned generation facilities may have unaligned goals and positions due to the effects of legislation, regulations, economic conditions or changes in our industry, which could have a significant impact on our ability to continue operations of such facilities.
APS owns certain of our power plants jointly with other owners with varying ownership interests in such facilities. Changes in the nature of our industry and the economic viability of certain plants, including impacts resulting from types and availability of other resources, fuel costs, legislation and regulation, together with timing considerations related to expiration of leases or other agreements for such facilities, could result in unaligned positions among co-owners. Such differences in the co-owners’ willingness or ability to continue their participation could ultimately lead to disagreements among the parties as to how and whether to continue operation of such plants, which could lead to eventual shut down of units or facilities and uncertainty related to the resulting cost recovery of such assets. (See Note 4 for a discussion of the Navajo Plant and Cholla retirement and the related risks associated with APS’s continued recovery of its remaining investment in the plant.)
Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on APS’s business and its results of operations.
In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona.  Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital.  Although some very limited retail competition existed in APS’s service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’s customers.  This is in large part due to a 2004 Arizona Court of Appeals decision that found critical components of the ACC’s rules to be violative of the Arizona Constitution. The ruling also voided the operating authority of all the competitive providers previously authorized by the ACC. 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 is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition. 
One of these options would be a continuation or expansion of APS’s existing AG (Alternative Generation)-X program, which essentially allows up to 200 MW of cumulative load to be served via a buy-through arrangement with competitive suppliers of generation.  The AG-X program was approved by the ACC as part of the 2017 Settlement Agreement (as defined in Note 4).
In November 2018, the ACC voted to again re-examine retail competition. In addition, proposals to enable or support retail electric competition may be made from time to time through ballot initiatives, legislative action or other forums in Arizona. The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules. APS cannot predict whether
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these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.
Changes in tax legislation or regulation may affect our financial results.
We are subject to taxation by various taxing authorities at the federal, state and local levels. Legislation or regulations could be enacted by any of these governmental authorities, which could affect the Company’s tax positions. The prospects for federal tax reform have increased due to the results of the recent elections. Any such reform may impact the Company’s effective tax rate, cash taxes paid and other financial results, such as earnings per share, gross revenues and cash flows. We cannot predict the timing or extent of such tax-related developments which, absent appropriate regulatory treatment, could have a negative impact on our financial results.
OPERATIONAL RISKS
APS’s results of operations can be adversely affected by various factors impacting demand for electricity.
Weather Conditions.  Weather conditions directly influence the demand for electricity and affect the price of energy commodities.  Electric power demand is generally a seasonal business.  In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time.  As a result, APS’s overall operating results fluctuate substantially on a seasonal basis.  In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder.  As a result, unusually mild weather could diminish APS’s financial condition, results of operations or cash flows.
Apart from the impact upon electricity demand, weather conditions related to prolonged high temperatures or extreme heat events present operational challenges. In the southwestern United States, where APS conducts its business, the effects of climate change are projected to increase the overall average temperature, lead to more extreme temperature events, and exacerbate prolonged drought conditions leading to the declining availability of water resources. Extreme heat events and rising temperatures are projected to reduce the generation capacity of thermal-power plants and decrease the efficiency of the transmission grid. These operational risks related to rising temperatures and extreme heat events could affect APS’s financial condition, results of operations or cash flows.
Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires.  Forest fires could threaten APS’s communities and electric transmission lines and facilities.  Any damage caused as a result of forest fires could negatively impact APS’s financial condition, results of operations or cash flows. In addition, the decrease in snowpack can also lead to reduced water supplies in the areas where APS relies upon non-renewable water resources to supply cooling and process water for electricity generation. Prolonged and extreme drought conditions can also affect APS’s long-term ability to access the water resources necessary for thermal electricity generation operations. Reductions in the availability of water for power plant cooling could negatively impact APS’s financial condition, results of operations or cash flows.
Effects of Energy Conservation Measures and Distributed Energy Resources.  The ACC has enacted rules regarding energy efficiency that mandate a 22% cumulative annual energy savings requirement by 2020.  This will likely increase participation by APS customers in energy efficiency and conservation programs and other demand-side management efforts, which in turn will impact the demand for electricity.  The rules also include a requirement for the ACC to review and address financial disincentives, recovery of fixed costs and the recovery of net lost revenue that would result from lower sales due to increased energy efficiency requirements.  To that end, the LFCR is designed to address these matters.
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APS must also meet certain distributed energy requirements.  A portion of APS’s total renewable energy requirement must be met with an increasing percentage of distributed energy resources (generally, small scale renewable technologies located on customers’ properties).  The distributed energy requirement is 30% of the applicable RES requirement for 2012 and subsequent years.  Customer participation in distributed energy programs would result in lower demand, since customers would be meeting some of their own energy needs.
In addition to these rules and requirements, energy efficiency technologies and distributed energy resources continue to evolve, which may have similar impacts on demand for electricity. Reduced demand due to these energy efficiency requirements, distributed energy requirements and other emerging technologies, unless substantially offset through ratemaking mechanisms, could have a material adverse impact on APS’s financial condition, results of operations and cash flows.
Actual and Projected Customer and Sales Growth.  Retail customers in APS’s service territory increased 2.3% for the year ended December 31, 2020 compared with the prior-year period. For the three years 2018 through 2020, APS’s customer growth averaged 2.0% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2021 and for 2021 through 2023 based on our assessment of steady population growth in Arizona. 
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.4% for the year ended December 31, 2020 compared with the prior-year period. While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation 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 2018 through 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 0.5% to 1.5% for 2021 and increase on average in the range of 1.0% to 2.0% during 2021 through 2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. This projected sales growth range now includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers 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, distributed renewable generation initiatives.
Actual customer and sales growth 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. Additionally, recovery of a substantial portion of our fixed costs of providing service is based upon the volumetric amount of our sales.  If our customer growth rate does not continue to improve as projected, or if we experience acceleration of expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives, we may be unable to reach our estimated sales
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projections, which could have a negative impact on our financial condition, results of operations and cash flows.
The operation of power generation facilities and transmission systems involves risks that could result in reduced output or unscheduled outages, which could materially affect APS’s results of operations.
The operation of power generation, transmission and distribution facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency.  Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications, occur from time to time and are an inherent risk of APS’s business.  Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the larger transmission power grid, and the operation or failure of our facilities could adversely affect the operations of others.  Concerns over physical security of these assets could include damage to certain of our facilities due to vandalism or other deliberate acts that could lead to outages or other adverse effects. If APS’s facilities operate below expectations, especially during its peak seasons, it may lose revenue or incur additional expenses, including increased purchased power expenses. 
The impact of wildfires could negatively affect APS’s results of operations.
Wildfires have the potential to affect the communities that APS serves and APS’s vast network of electric transmission and distribution lines and facilities. The potential likelihood of wildfires has increased due to many of the same weather impacts existing in Arizona as those that led to the catastrophic wildfires in Northern California. While we proactively take steps to mitigate wildfire risk in the areas of our electrical assets, wildfire risk is always present due to APS’s expansive service territory. APS could be held liable for damages incurred as a result of wildfires if it was determined that they were caused by or enhanced due to APS’s negligence. The Arizona liability standard is different from that of California, which generally imposes liability for resulting damages without regard to fault. Any damage caused to our assets, loss of service to our customers, or liability imposed as a result of wildfires could negatively impact APS’s financial condition, results of operations or cash flows.
The inability to successfully develop, acquire or operate generation resources to meet reliability requirements and other new or evolving standards or regulations could adversely impact our business.
Potential changes in regulatory standards, impacts of new and existing laws and regulations, including environmental laws and regulations, and the need to obtain various regulatory approvals create uncertainty surrounding our current and future generation portfolio. The current regulatory standards, laws, and regulations create strategic challenges as to the appropriate generation portfolio and fuel diversification mix. In addition, APS is required by the ACC to meet certain energy resource portfolio requirements, including those related to carbon emissions, renewables development and energy efficiency measures. The development of any generation facility is also subject to many risks, including those related to financing, siting, permitting, new and evolving technology, and the construction of sufficient transmission capacity to support these facilities. APS’s inability to adequately develop or acquire the necessary generation resources could have a material adverse impact on our business and results of operations.
In expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the permitting, construction, and operation of fossil fuel infrastructure projects. These efforts may increase in scope and frequency depending on a number of variables, including the future course of Federal environmental regulation and the increasing financial resources devoted to these opposition activities. APS cannot predict the effect that
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any such opposition may have on our ability to develop, construct and operate fossil fuel infrastructure projects in the future.
In January 2020, APS announced its goal to provide 100% clean, carbon-free electricity by 2050 with an intermediate 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy. APS’s ability to successfully execute its clean energy commitment is dependent upon a number of external factors, some of which include supportive national and state energy policies, a supportive regulatory environment, sales and customer growth, the development, deployment and advancement of clean energy technologies and continued access to capital markets.
The lack of access to sufficient supplies of water could have a material adverse impact on APS’s business and results of operations.
Assured supplies of water are important for APS’s generating plants.  Water in the southwestern United States is limited, and various parties have made conflicting claims regarding the right to access and use such limited supply of water.  Both groundwater and surface water in areas important to APS’s generating plants have been and are the subject of inquiries, claims and legal proceedings.  In addition, the region in which APS’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies.  Climate change is also projected to exacerbate prolonged drought conditions. APS’s inability to access sufficient supplies of water could have a material adverse impact on our business and results of operations.
We are subject to cybersecurity risks and risks of unauthorized access to our systems that could adversely affect our business and financial condition.
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In the regular course of our business, we handle a range of sensitive security, customer and business systems information. There appears to be an increasing level of activity, sophistication and maturity of threat actors, in particular nation state actors, that seek to exploit potential vulnerabilities in the electric utility industry and wish to disrupt the U.S. bulk power, transmission and distribution system. Our information technology systems, generation (including our Palo Verde nuclear facility), transmission and distribution facilities, and other infrastructure facilities and systems and physical assets could be targets of unauthorized access and are critical areas of cyber protection for us.
We rely extensively on IT systems, networks, and services, including internet sites, data hosting and processing facilities, and other hardware, software and technical applications and platforms. Some of these systems are managed, hosted, provided, or used for third parties to assist in conducting our business. Malicious actors may attack vendors to disrupt the services these vendors provide to us or to use those vendors as a cyber conduit to attack us. As more third parties are involved in the operation of our business, there is a risk the confidentiality, integrity, privacy or security of data held by, or accessible to, third parties may be compromised.
If a significant cybersecurity event or breach were to occur, we may not be able to fulfill critical business functions and we could (i) experience property damage, disruptions to our business, theft of or unauthorized access to customer, employee, financial or system operation information or other information; (ii) experience loss of revenue or incur significant costs for repair, remediation and breach notification, and increased capital and operating costs to implement increased security measures; and (iii) be subject to increased regulation, litigation and reputational damage. If such disruptions or breaches are not detected quickly, their effect could be compounded or could delay our response or the effectiveness of our response and ability to limit our exposure to potential liability. These types of events could also
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require significant management attention and resources, and could have a material adverse impact on our financial condition, results of operations or cash flows.
We develop and maintain systems and processes aimed at detecting and preventing information and cybersecurity incidents which require significant investment, maintenance, and ongoing monitoring and updating as technologies and regulatory requirements change. These systems and processes may be insufficient to mitigate the possibility of information and cybersecurity incidents, malicious social engineering, fraudulent or other malicious activities, and human error or malfeasance in the safeguarding of our data.
We are subject to laws and rules issued by multiple government agencies concerning safeguarding and maintaining the confidentiality of our security, customer and business information. One of these agencies, NERC, has issued comprehensive regulations and standards surrounding the security of bulk power systems, and is continually in the process of developing updated and additional requirements with which the utility industry must comply. The NRC also has issued regulations and standards related to the protection of critical digital assets at commercial nuclear power plants. The increasing promulgation of NERC and NRC rules and standards will increase our compliance costs and our exposure to the potential risk of violations of the standards. Experiencing a cybersecurity incident could cause us to be non-compliant with applicable laws and regulations, such as those promulgated by NERC and the NRC, privacy laws, or contracts that require us to securely maintain confidential data, causing us to incur costs related to legal claims or proceedings and regulatory fines or penalties.
The risk of these system-related events and security breaches occurring continues to intensify. We have experienced, and expect to continue to experience, threats and attempted intrusions to our information technology systems and we could experience such threats and attempted intrusions to our operational control systems. To date we do not believe we have experienced a material breach or disruption to our network or information systems or our service operations. We may not be able to anticipate and prevent all cyberattacks or information security breaches, and our ongoing investments in security resources, talent, and business practices may not be effective against all threat actors. As such attacks continue to increase in sophistication and frequency, we may be unable to prevent all such attacks from being successful in the future.
We maintain cyber insurance to provide coverage for a portion of the losses and damages that may result from a security breach of our information technology systems, but such insurance is subject to a number of exclusions and may not cover the total loss or damage caused by a breach. Coverage for cybersecurity events continues to evolve as the industry matures. In the future, adequate insurance may not be available at rates that we believe are reasonable, and the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable in rates.
The ownership and operation of power generation and transmission facilities on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.
Four Corners and portions of certain APS transmission lines are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods.  APS is unable to predict the final outcomes of pending and future approvals by the applicable sovereign governing bodies with respect to renewals of these leases, easements and rights-of-way.
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There are inherent risks in the ownership and operation of nuclear facilities, such as environmental, health, fuel supply, spent fuel disposal, regulatory and financial risks and the risk of terrorist attack that could adversely affect our business and financial condition.
APS has an ownership interest in and operates, on behalf of a group of participants, Palo Verde, which is the largest nuclear electric generating facility in the United States.  Palo Verde constitutes approximately 18% of our owned and leased generation capacity.  Palo Verde is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel; the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; and unscheduled outages due to equipment and other problems.  APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.  In addition, APS may be required under federal law to pay up to $120.1 million (but not more than $17.9 million per year) of liabilities arising out of a nuclear incident occurring not only at Palo Verde, but at any other nuclear power reactor in the United States. Although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations and financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
Changes in technology could create challenges for APS’s existing business.
Alternative energy technologies that produce power or reduce power consumption or emissions are being developed and commercialized, including renewable technologies such as photovoltaic (solar) cells, customer-sited generation, energy storage (batteries) and efficiency technologies.  Advances in technology and equipment/appliance efficiency could reduce the demand for supply from conventional generation, including carbon-free nuclear generation, and increase the complexity of managing APS’s information technology and power system operations, which could adversely affect APS’s business.
Customer-sited alternative energy technologies present challenges to APS’s operations due to misalignment with APS’s existing operational needs. When these resources lack “dispatchability” and other elements of utility-side control, they are considered “unmanaged” resources. The cumulative effect of such unmanaged resources results in added complexity for APS’s system management.
APS continues to pursue and implement advanced grid technologies, including transmission and distribution system technologies and digital meters enabling two-way communications between the utility and its customers.  Many of the products and processes resulting from these and other alternative technologies, including energy storage technologies, have not yet been widely used or tested on a long-term basis, and their use on large-scale systems is not as established or mature as APS’s existing technologies and equipment.  The implementation of new and additional technologies adds complexity to our information technology and operational technology systems, which could require additional infrastructure and resources. Widespread installation and acceptance of new technologies could also enable the entry of new market participants, such as technology companies, into the interface between APS and its customers and could have other unpredictable effects on APS’s traditional business model.
Deployment of renewable energy technologies is expected to continue across the western states and result in a larger portion of the overall energy production coming from these sources. These trends, which have benefited from historical and continuing government support for certain technologies, have the potential to put downward pressure on wholesale power prices throughout the western states which could
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make APS’s existing generating facilities less economical and impact their operational patterns and long-term viability.
We are subject to employee workforce factors that could adversely affect our business and financial condition.
Like many companies in the electric utility industry, our workforce is maturing, with approximately 31% of employees eligible to retire by the end of 2025.  Although we have undertaken efforts to recruit, train and develop new employees, we face increased competition for talent.  We are subject to other employee workforce factors, such as the availability and retention of qualified personnel and the need to negotiate collective bargaining agreements with union employees.  These or other employee workforce factors could negatively impact our business, financial condition or results of operations.
The outbreak of the COVID-19 pandemic could negatively affect our business. 
The outbreak of COVID-19 is a rapidly developing situation around the globe that has led to economic disruption and volatility in the financial markets. The continued spread of COVID-19 and efforts to contain the virus could decrease demand for energy, lower economic growth, impact our employees and contractors, cause disruptions in our supply chain, increase certain costs, further increase volatility in the capital markets (and result in increases in the cost of capital or an inability to access the capital markets or draw on available credit facilities), delay the completion of capital or other construction projects and other operations and maintenance activities, delay payments or increase uncollectable accounts or cause other unpredictable events, each of which could adversely affect our business, results of operations, cash flows or financial condition.
As a result of the COVID-19 pandemic, from March through December 2020, we have experienced a decrease in demand from commercial and industrial customers and an increase in demand from residential customers and the cumulative impact on weather normalized retail electricity sales usage was a net increase as compared to 2019. APS is also experiencing an increase in bad debt expense associated with the COVID-19 pandemic that resulted in a negative impact to our 2020 operating results. In mid-March 2020, we drew on our revolving credit facilities as a result of the commercial paper markets failing to function normally due to COVID-19, but we were subsequently able to utilize the commercial paper market in April 2020 and we have paid down the revolving credit facilities completely. We are also experiencing increased operations and maintenance expenses due to the need for personal protective equipment and other health and safety-related costs related to COVID-19.
Despite our efforts to manage the impacts, the degree to which the COVID-19 pandemic and related actions ultimately impact our business, financial position, results of operations and cash flows will depend on factors beyond our control including the duration, spread and severity of the outbreak, the actions taken to contain COVID-19 and mitigate its public health effects, the impact on the U.S. and global economies and demand for energy, and how quickly and to what extent normal economic and operating conditions resume.
FINANCIAL RISKS
A downgrade of our credit ratings could materially and adversely affect our business, financial condition and results of operations.
Our current ratings are set forth in “Liquidity and Capital Resources — Credit Ratings” in Item 7.  We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Any downgrade or withdrawal could adversely affect the market price of Pinnacle West’s and APS’s securities, limit our access to capital and increase our borrowing costs, which would
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adversely impact our financial results.  We could be required to pay a higher interest rate for future financings, and our potential pool of investors and funding sources could decrease.  In addition, borrowing costs under our existing credit facilities depend on our credit ratings.  A downgrade could also require us to provide additional support in the form of letters of credit or cash or other collateral to various counterparties.  If our short-term ratings were to be lowered, it could severely limit access to the commercial paper market.  We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.
Investment performance, changing interest rates and other economic, social and political factors could decrease the value of our benefit plan assets, nuclear decommissioning trust funds and other special use funds or increase the valuation of our related obligations, resulting in significant additional funding requirements.  We are also subject to risks related to the provision of employee healthcare benefits and healthcare reform legislation.  Any inability to fully recover these costs in our utility rates would negatively impact our financial condition.
We have significant pension plan and other postretirement benefits plan obligations to our employees and retirees, and legal obligations to fund our pension trust and nuclear decommissioning trusts for Palo Verde.  We hold and invest substantial assets in these trusts that are designed to provide funds to pay for certain of these obligations as they arise.  Declines in market values of the fixed income and equity securities held in these trusts may increase our funding requirements into the related trusts.  Additionally, the valuation of liabilities related to our pension plan and other postretirement benefit plans are impacted by a discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations.  Declining interest rates decrease the discount rate, increase the valuation of the plan liabilities and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to OCI.  Changes in demographics, including increased number of retirements or changes in life expectancy and changes in other actuarial assumptions, may also result in similar impacts.  The minimum contributions required under these plans are impacted by federal legislation and related regulations.  Increasing liabilities or otherwise increasing funding requirements under these plans, resulting from adverse changes in legislation or otherwise, could result in significant cash funding obligations that could have a material impact on our financial position, results of operations or cash flows.
We recover most of the pension and other postretirement benefit expense and all of the currently estimated nuclear decommissioning costs in our regulated rates.  Any inability to fully recover these costs in a timely manner could have a material negative impact on our financial condition, results of operations or cash flows.
While most of the Patient Protection and Affordable Care Act provisions have been implemented, changes to or repeal of that Act and pending or future federal or state legislative or regulatory activity or court proceedings could increase costs of providing medical insurance for our employees and retirees. Any potential changes and resulting cost impacts cannot be determined with certainty at this time.
Our cash flow depends on the performance of APS and its ability to make distributions.
We derive essentially all of our revenues and earnings from our wholly-owned subsidiary, APS.  Accordingly, our cash flow and our ability to pay dividends on our common stock is dependent upon the earnings and cash flows of APS and its distributions to us.  APS is a separate and distinct legal entity and has no obligation to make distributions to us.
APS’s financing agreements may restrict its ability to pay dividends, make distributions or otherwise transfer funds to us.  In addition, an ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold.  The common equity ratio, as defined in the ACC order, is total
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shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.
Pinnacle West’s ability to meet its debt service obligations could be adversely affected because its debt securities are structurally subordinated to the debt securities and other obligations of its subsidiaries.
Because Pinnacle West is structured as a holding company, all existing and future debt and other liabilities of its subsidiaries will be effectively senior in right of payment to its own debt securities.  The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations.  Our ability to have the benefit of their cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.
The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.
APS’s operations include managing market risks related to commodity prices.  APS is exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas and coal to the extent that unhedged positions exist.  We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange traded futures and over-the-counter forwards, options, and swaps.  As part of our overall risk management program, we enter into derivative transactions 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 commodity.  To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time and financial losses that negatively impact our results of operations.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict, among other things, trading positions in the energy futures markets, require different collateral or settlement positions, or increase regulatory reporting over derivative positions. Based on the provisions included in the Dodd-Frank Act and the implementation of regulations, these changes could, among other things, impact our ability to hedge commodity price and interest rate risk or increase the costs associated with our hedging programs.
We are exposed to losses in the event of nonperformance or nonpayment by counterparties.  We use a risk management process to assess and monitor the financial exposure of all counterparties.  Despite the fact that the majority of APS’s trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, which could result in a material adverse impact on our earnings for a given period.
GENERAL RISKS
Proposals to change policy in Arizona or other states made through ballot initiatives or referenda may increase the Company’s cost of operations or impact its business plans.
In Arizona and other states, a person or organization may file a ballot initiative or referendum with the Arizona Secretary of State or other applicable state agency and, if a sufficient number of verifiable signatures are presented, the initiative or referendum may be placed on the ballot for the public to vote on the matter. Ballot initiatives and referenda may relate to any matter, including policy and regulation related to the electric industry, and may change statutes or the state constitution in ways that could impact Arizona utility customers, the Arizona economy and the Company. Some ballot initiatives and referenda are drafted in an unclear manner and their potential industry and economic impact can be subject to varied
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and conflicting interpretations. We may oppose certain initiatives or referenda (including those that could result in negative impacts to our customers, the state or the Company) via the electoral process, litigation, traditional legislative mechanisms, agency rulemaking or otherwise, which could result in significant costs to the Company. The passage of certain initiatives or referenda could result in laws and regulations that impact our business plans and have a material adverse impact on our financial condition, results of operations or cash flows.
The market price of our common stock may be volatile.
The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:
variations in our quarterly operating results;
operating results that vary from the expectations of management, securities analysts and investors;
changes in expectations as to future financial performance, including financial estimates by securities analysts and investors;
developments generally affecting industries in which we operate;
announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
announcements by third parties of significant claims or proceedings against us;
favorable or adverse regulatory or legislative developments;
our dividend policy;
future sales by the Company of equity or equity-linked securities; and
general domestic and international economic conditions.
In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company.  These broad market fluctuations may adversely affect the market price of our common stock.
Financial market disruptions or new rules or regulations may increase our financing costs or limit our access to various financial markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
Pinnacle West and APS rely on access to credit markets as a significant source of liquidity and the capital markets for capital requirements not satisfied by cash flow from our operations.  We believe that we will maintain sufficient access to these financial markets.  However, certain market disruptions or revisions to rules or regulations may cause our cost of borrowing to increase generally, and/or otherwise adversely affect our ability to access these financial markets.
In addition, the credit commitments of our lenders under our bank facilities may not be satisfied or continued beyond current commitment periods for a variety of reasons, including new rules and regulations, periods of financial distress or liquidity issues affecting our lenders or financial markets, which could materially adversely affect the adequacy of our liquidity sources and the cost of maintaining these sources.
Changes in economic conditions, monetary policy, fiscal policy, financial regulation, rating agency treatment or other factors could result in higher interest rates, which would increase interest expense on our
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existing variable rate debt and new debt we expect to issue in the future, and thus increase the cost and/or reduce the amount of funds available to us for our current plans.
Additionally, an increase in our leverage, whether as a result of these factors or otherwise, could adversely affect us by:
causing a downgrade of our credit ratings;
increasing the cost of future debt financing and refinancing;
increasing our vulnerability to adverse economic and industry conditions; and
requiring us to dedicate an increased portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future investment in our business or other purposes.
Certain provisions of our articles of incorporation and bylaws and of Arizona law make it difficult for shareholders to change the composition of our board and may discourage takeover attempts.
These provisions, which could preclude our shareholders from receiving a change of control premium, include the following:
restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who beneficially owns 10% or more of our outstanding voting power, or any of our affiliates or associates who beneficially owned 10% or more of our outstanding voting power at any time during the prior three years) or any affiliate or associate of an interested shareholder, unless specific conditions are met;
anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;
the ability of the Board of Directors to increase the size of and fill vacancies on the Board of Directors, whether resulting from such increase, or from death, resignation, disqualification or otherwise;
the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval;
restrictions that limit the rights of our shareholders to call a special meeting of shareholders; and
restrictions regarding the rights of our shareholders to nominate directors or to submit proposals to be considered at shareholder meetings.
While these provisions may have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board of Directors to hinder or frustrate a transaction that some, or a majority, of our shareholders might believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors.

ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2020 fiscal year and that remain unresolved.

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ITEM 2.  PROPERTIES
Generation Facilities  
    
APS’s portfolio of owned generating facilities as of December 31, 2020 is provided in the table below:
Name No. of
Units
%
Owned (a)
Principal
Fuels
Used
Primary
Dispatch
Type
Owned
Capacity
(MW)
Nuclear:          
Palo Verde (b) 3 29.1  % Uranium Base Load 1,146 
Total Nuclear         1,146 
Steam:          
Four Corners 4, 5 (c) 2 63  % Coal Base Load 970 
Cholla 1,3 2   Coal Base Load 387 
Total Steam         1,357 
Combined Cycle:          
Redhawk (e) 2   Gas Load Following 1,088 
West Phoenix 5   Gas Load Following 887 
Total Combined Cycle         1,975 
Combustion Turbine:          
Ocotillo (d) 7   Gas Peaking 620 
Saguaro 3   Gas Peaking 189 
Douglas/Fairview 1   Oil Peaking 16 
Sundance 10   Gas Peaking 420 
West Phoenix 2   Gas Peaking 110 
Yucca 1, 2, 3 3   Gas Peaking 93 
Yucca 4 1   Oil Peaking 54 
Yucca 5, 6 2   Gas Peaking 96 
Total Combustion Turbine         1,598 
Solar:          
Cotton Center (f) 1   Solar As Available 17 
Hyder I (f) 1   Solar As Available 16 
Paloma (f) 1   Solar As Available 17 
Chino Valley 1   Solar As Available 19 
Gila Bend (f) 1 Solar As Available 32 
Hyder II (f) 1   Solar As Available 14 
Foothills (f) 1   Solar As Available 35 
Luke AFB 1 Solar As Available 10 
Desert Star (f) 1 Solar As Available 10 
Red Rock 1 Solar As Available 40 
APS Owned Distributed Energy     Solar As Available 31 
Multiple facilities     Solar As Available
Total Solar         245 
Total Capacity         6,321 
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(a)100% unless otherwise noted.
(b)Our 29.1% ownership in Palo Verde includes leased interests. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%).  The plant is operated by APS.
(c)The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), Tucson Electric Power Company (7%) and NTEC (7%).  The plant is operated by APS. 
(d)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.
(e)Redhawk generation capacity increased by 104 MW following the Advanced Gas Path upgrade installed on both units.
(f)APS is under contract and currently plans to add battery storage at these AZ Sun sites. (See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Energy Storage” above for details related to these and other energy storage agreements.)

See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’s generating facilities.
 
See “Business of Arizona Public Service Company” in Item 1 for a map detailing the location of APS’s major power plants and principal transmission lines.

4CA

4CA, a wholly-owned subsidiary of Pinnacle West, purchased El Paso’s 7% interest in Units 4 and 5 of Four Corners on July 6, 2016 and subsequently sold the interest to NTEC on July 3, 2018. (See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Coal-Fueled Generating Facilities — Four Corners” in Item 1 and “Four Corners — 4CA Matter” in Note 11 for additional information about 4CA’s interest in Four Corners.)
 
Transmission and Distribution Facilities
 
Current Facilities.  APS’s transmission facilities consist of approximately 5,728 pole miles of overhead lines and approximately 74 miles of underground lines, 5,591 miles of which are located in Arizona.  APS’s distribution facilities consist of approximately 11,225 miles of overhead lines and approximately 22,453 miles of underground primary cable, all of which are located in Arizona. APS also owns and maintains 80 transmission substations and 443 distribution substations. APS shares ownership of some of its transmission facilities with other companies. 



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The following table shows APS’s jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2020:
  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 26.0  %
Four Corners Switchyards 61.8  %
Palo Verde — Yuma 500kV System 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  %
 
Expansion.  Each year APS prepares and files with the ACC a ten-year transmission plan.  In APS’s 2021 plan, APS projects it will develop 26 miles of new transmission lines over the next ten years. One significant project, the Palo Verde to Morgan project recently completed all phases and provides a new 500kV path that spans from the Palo Verde hub around the western and northern edges of the Phoenix metropolitan area and terminates at a bulk substation in the northeast part of Phoenix. The Palo Verde to Morgan project includes Palo Verde-Delaney-Sun Valley-Morgan-Pinnacle Peak. The project consisted of four phases and the fourth phase, Morgan to Sun Valley 500kV, was energized in April of 2018. In total, the project consisted of over 100 miles of new 500kV lines, with many of those miles constructed with the capability to employ a 230kV line as a second circuit.

APS continues to work with regulators to identify transmission projects necessary to support renewable energy facilities. Two such projects, which have been completed and were included in previous APS transmission plans, are the Delaney to Palo Verde line and the North Gila to Hassayampa line, both of which support the transmission of renewable energy to Phoenix and California. The North Gila to Hassayampa line went into service in May 2015 and the Delaney to Palo Verde line went into service in May 2016.

Plant and Transmission Line Leases and Rights-of-Way on Indian Lands
 
The Navajo Plant and Four Corners are located on land held under leases from the Navajo Nation and also under rights-of-way from the federal government.   The Navajo Plant ceased operations in 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.

APS, on behalf of the Four Corners participants, negotiated amendments to the Four Corners facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041.  See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generating Facilities — Coal-Fueled Generating Facilities — Four Corners” in Item 1 for additional information about the Four Corners right-of-way and lease matters.

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Certain portions of our transmission lines are located on Indian lands pursuant to rights-of-way that are effective for specified periods.  Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes or federal agencies.  Other rights expire at various times in the future and renewal action by the applicable tribe or federal agencies will be required at that time.  In recent negotiations, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way.  The ultimate cost of renewal of certain of the rights-of-way for our transmission lines is therefore uncertain.

ITEM 3.  LEGAL PROCEEDINGS
 
See “Business of Arizona Public Service Company — Environmental Matters” in Item 1 with regard to pending or threatened litigation and other disputes.
See Note 4 for ACC and FERC-related matters.
See Note 11 for information regarding environmental matters, Superfund–related matters and other disputes. 

ITEM 4.  MINE SAFETY DISCLOSURES
 
Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Pinnacle West’s executive officers are elected no less often than annually and may be removed by the Board of Directors, or in certain cases also by the Human Resources Committee, at any time.  The executive officers, their ages at February 24, 2021, current positions and principal occupations for the past five years are as follows:
Name Age Position Period
Jeffrey B. Guldner 55 Chairman of the Board, President and Chief Executive 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
Elizabeth A. Blankenship 49 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 42 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 56 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 59 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 42 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 63 Chief Administrative Officer 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 60 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 54 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
Robert E. Smith 51 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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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 17, 2021, Pinnacle West’s common stock was held of record by approximately 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, 2020, APS did not have any outstanding preferred stock.
Stock Performance Chart
This graph compares the cumulative total shareholder return on Pinnacle West’s common stock during the five years ended December 31, 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 in Pinnacle West's common stock and in each of the indices shown and that all of the dividends were reinvested.
PNW-20201231_G4.JPG
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
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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 2020 results with 2019 results. A comparison of the 2019 results with 2018 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, 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 $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.

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
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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 clean, reliable and 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 a shared, sustainable vision for Arizona. This goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

APS’s new clean energy goals consist of three parts:
A 2050 goal to provide 100% clean, carbon-free electricity;
A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and
A commitment to end APS’s use of coal-fired generation by 2031.

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 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 Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of 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 Use of Coal-Fired Generation. The commitment to end APS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation 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 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, all of which lead to a cleaner 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. Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of 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

We believe it is 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 7.3%, or $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 internal efficiencies. Through the initiative and existing cost management practices, APS met its goal of $20 million in cost savings as of December 31, 2020.

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.

Reliable

While our energy mix evolves, the obligation to deliver reliable service to our customers remains. 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 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.

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

Customers are at the core of what APS does every day and its focus remains on its customers and the communities it serves. It is APS’s goal to achieve an industry-leading best-in-class customer experience.

In 2020, APS 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 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 customer needs, wants, and perspectives. Additionally, the customer advisory board is leveraged to identify and diagnose potential customer 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 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 the agreement was scheduled to begin in 2021; however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date. In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. These battery storage facilities are expected to be in service by June 2022. Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. APS has now completed its investigation of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs. These PPAs were also subject to ACC approval in order to allow for cost recovery through the PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

We currently plan to install at least 850 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites that were not included in the 2018 RFP referenced in the preceding paragraph; and (ii) an ‘all source’ RFP that solicits both standalone energy storage and renewable energy plus energy storage resources. Such resources would be expected to be in service during 2023 and 2024.

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Electric Vehicles

APS is making electric vehicle charging more accessible for its customers and helping Arizona businesses, schools and governments electrify their fleets. In 2020, APS expanded its Take Charge AZ Pilot 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. In addition to the Level 2 charging stations, APS will begin construction of direct current fast charging stations that will be owned and operated by APS at five locations in Arizona. This project is 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 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 2023. In the first phase, Idaho National Laboratory will perform a technical and economic assessment of using electricity generated at Palo Verde to produce hydrogen.

Experience from Palo Verde’s utility partners’ demonstration projects and from the Palo Verde-specific technical economic assessment is expected to offer insights into methods for flexible transitions between electricity and hydrogen generation in solar-dominated electricity markets.

Carbon Capture

Carbon capture technologies can isolate 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. 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. APS will continue to monitor this emerging technology.

Regulatory Overview

On October 31, 2019, APS filed an application with the ACC 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 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 application 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  % 4.1 %
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 Base Fuel Rate of $0.030168 per kWh;
authorization to defer until 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 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 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 strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry.  In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.  The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.

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

El Dorado. 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 2018 through 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 2.3% for the year ended December 31, 2020 compared with the prior-year period. For the three years 2018 through 2020, APS’s customer growth averaged 2.0% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2021 and for 2021 through 2023 based on our assessment of steady population growth in Arizona.

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Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.4% for the year ended December 31, 2020 compared with the prior-year period. While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation 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 2018 through 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 0.5% to 1.5% for 2021 and increase on average in the range of 1.0% to 2.0% during 2021 through 2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. This projected sales growth range now includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers 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, distributed renewable generation 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 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 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 approximately $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 and Capital Resources” below for information regarding the planned additions to our 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 10.8% of the assessed value for 2020, 10.9% for 2019 and 11.0% for 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”) 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, 2020.) In 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 – 2020 compared with 2019

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

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Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $164 million higher for the year ended December 31, 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)
Lost fixed cost recovery
— 
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) (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 

Operations and maintenance.  Operations and maintenance expenses increased $14 million for the year ended December 31, 2020 compared with the prior-year period primarily because of:
An increase of $25 million primarily related to COVID Customer Support Fund, personal protective equipment and other health and safety-related costs for COVID-19 response (see Note 4);
An increase of $22 million related to employee 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 $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;
A decrease of $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 $23 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to increased plant in service of $37 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $17 million.

Taxes other than income taxes.  Taxes other than income taxes were $6 million higher for the year ended December 31, 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 $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, 2020 compared to the prior-year period primarily due to 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 the current period.

Income taxes.  Income taxes were $94 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to higher pre-tax net income and lower amortization of excess deferred taxes, 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, 2020, APS’s common equity ratio, as defined, was 51%.  Its total shareholder equity was approximately $6.2 billion, and total capitalization was approximately $12.2 billion.  Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.9 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, 2020 and 2019 (dollars in millions):

Pinnacle West Consolidated
  2020 2019
Net cash flow provided by operating activities $ 967  $ 957 
Net cash flow used for investing activities (1,278) (1,131)
Net cash flow provided by financing activities 361  179 
Net increase in cash and cash equivalents $ 50  $
 
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  $

 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.

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.

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
 
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
 
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.    

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 FacilitiesPinnacle 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 A3   A-   A-
Senior unsecured A3   BBB+   A-
Commercial paper P-2   A-2   F2
Outlook Negative   Stable   Negative
           
APS          
Corporate credit rating A2   A-   A-
Senior unsecured A2   A-   A
Commercial paper P-1   A-2   F2
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 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 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
 
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 $1,426 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 
Healthcare cost trend rate (b):
Increase 1% 86 
Decrease 1% (70) (4)
Expected long-term rate of return on plan assets – pretax:
Increase 1% —  (5)
Decrease 1% — 
(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
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) $ —  $ — 
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
   
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85
89
90
91
93
94
   
95
96
100
101
102
104
105
106
106
115
117
118
139
143
144
147
156
159
160
168
169
175
175
178
182
183
183
187
 
 

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Table of Contents
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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Table of Contents
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 Pinnacle West Capital Corporation 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 schedules 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

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 24, 2021

We have served as the 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) —  (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)
—  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)
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) — 
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) —  — 
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

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

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 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.
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 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,
  2020 2019 2018
OPERATING REVENUES (NOTE 2)
$ 3,586,982  $ 3,471,209  $ 3,688,342 
OPERATING EXPENSES      
Fuel and purchased power 993,419  1,042,237  1,094,020 
Operations and maintenance 945,181  926,716  969,227 
Depreciation and amortization 614,293  590,844  580,694 
Taxes other than income taxes 224,790  218,540  212,136 
Other expense 7,288  5,888  2,497 
Total 2,784,971  2,784,225  2,858,574 
OPERATING INCOME 802,011  686,984  829,768 
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)
57,359  24,529  51,242 
Other income (Note 17)
51,755  46,884  22,746 
Other expense (Note 17)
(53,694) (12,990) (15,292)
Total 89,196  89,854  111,015 
INTEREST EXPENSE      
Interest charges 233,452  220,174  231,391 
Allowance for borrowed funds used during construction (Note 1)
(18,530) (18,528) (25,180)
Total 214,922  201,646  206,211 
INCOME BEFORE INCOME TAXES 676,285  575,192  734,572 
INCOME TAXES (Note 5)
88,764  (9,572) 144,814 
NET INCOME 587,521  584,764  589,758 
Less: Net income attributable to noncontrolling interests
(Note 18)
19,493  19,493  19,493 
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,
  2020 2019 2018
NET INCOME $ 587,521  $ 584,764  $ 589,758 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX      
Derivative instruments:      
Net unrealized loss, net of tax benefit (expense) of $(18), $0, and $(78)
(18) —  (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 $1,955, $3,136, and $(1,159) (Note 8)
(5,970) (9,552) 3,465 
Total other comprehensive income (loss) (5,396) (8,415) 4,914 
COMPREHENSIVE INCOME 582,125  576,349  594,672 
Less: Comprehensive income attributable to noncontrolling interests 19,493  19,493  19,493 
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,
  2020 2019
ASSETS    
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
   
Plant in service and held for future use $ 20,834,424  $ 19,832,805 
Accumulated depreciation and amortization (7,107,058) (6,634,597)
Net 13,727,366  13,198,208 
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 $697,366 and $646,142
282,415  290,409 
Nuclear fuel, net of accumulated amortization of $137,207 and $137,330
113,645  123,500 
Total property, plant and equipment 15,158,846  14,522,156 
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 46,010  43,781 
Total investments and other assets 1,438,954  1,299,651 
CURRENT ASSETS    
Cash and cash equivalents 57,310  10,169 
Customer and other receivables 312,644  255,479 
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)
—  7,313 
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 47,593  38,895 
Total current assets 1,158,903  981,492 
DEFERRED DEBITS    
Regulatory assets (Notes 1, 4, and 5)
1,133,987  1,304,073 
Operating lease right-of-use assets (Note 9)
503,475  144,024 
Assets for pension and other postretirement benefits (Note 8)
495,673  86,736 
Other 34,413  32,591 
Total deferred debits 2,167,548  1,567,424 
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,
  2020 2019
LIABILITIES AND EQUITY    
CAPITALIZATION    
Common stock $ 178,162  $ 178,162 
Additional paid-in capital 2,871,696  2,721,696 
Retained earnings 3,216,955  3,011,927 
Accumulated other comprehensive loss (Note 20)
(40,918) (35,522)
Total shareholder equity 6,225,895  5,876,263 
Noncontrolling interests (Note 18)
119,290  122,540 
Total equity 6,345,185  5,998,803 
Long-term debt less current maturities (Note 7)
5,817,945  4,833,133 
Total capitalization 12,163,130  10,831,936 
CURRENT LIABILITIES    
Current maturities of long-term debt (Note 7)
—  350,000 
Accounts payable 311,699  338,006 
Accrued taxes 148,970  136,328 
Accrued interest 56,322  52,619 
Common dividends payable 93,500  88,000 
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)
74,695  12,549 
Regulatory liabilities (Note 4)
229,088  234,912 
Other current liabilities 190,420  164,736 
Total current liabilities 1,176,177  1,492,029 
DEFERRED CREDITS AND OTHER    
Deferred income taxes (Note 5)
2,143,673  2,033,096 
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)
148,943  262,243 
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)
39,410  40,188 
Operating lease liabilities (Note 9)
359,653  50,092 
Other 160,036  136,432 
Total deferred credits and other 6,584,944  6,046,758 
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
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,
  2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 587,521  $ 584,764  $ 589,758 
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation and amortization including nuclear fuel 686,168  664,055  649,295 
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 36,462  48,367  59,927 
Deferred investment tax credit (5,096) (3,938) (5,170)
Changes in current assets and liabilities:      
Customer and other receivables (28,206) (12,075) 35,406 
Accrued unbilled revenues (4,032) 9,005  (24,736)
Materials, supplies and fossil fuel 11,623  (51,826) (6,206)
Income tax receivable 7,313  (7,313) — 
Other current assets (24,669) (1,461) 31,707 
Accounts payable (4,503) 53,258  (15,608)
Accrued taxes 12,642  (40,029) 19,008 
Other current liabilities 29,587  (82,138) 25,070 
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 (65,139) (85,725) 77,952 
Change in other long-term liabilities (186,871) (129,682) (55,169)
Net cash flow provided by operating activities 929,067  1,007,411  1,254,801 
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures (1,326,584) (1,191,447) (1,169,061)
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 (554) 6,336  (1,789)
Net cash flow used for investing activities (1,286,255) (1,136,093) (1,187,446)
CASH FLOWS FROM FINANCING ACTIVITIES      
Issuance of long-term debt 1,099,722  1,092,188  295,245 
Repayment of long-term debt (465,150) (600,000) (182,000)
Short-term debt borrowings under revolving credit facility 540,000  —  25,000 
Short-term debt repayments under revolving credit facility (540,000) —  (25,000)
Dividends paid on common stock (357,500) (336,300) (316,000)
Equity infusion from Pinnacle West 150,000  —  150,000 
Noncontrolling interests (22,743) (22,744) (22,744)
Net cash flow provided by (used for) financing activities 404,329  133,144  (75,499)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 47,141  4,462  (8,144)
CASH AND CASH EQUIVALENTS AT BEGINNING 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) —  — 
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 

(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 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 7% interest in Four Corners. (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 Note 18 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”).  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
 
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” 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 accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections 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, 2020 and 2019 Consolidated Balance Sheets is composed of the following (dollars in thousands):

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 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, 2020 were as follows:
Fossil plant — 17 years;
Nuclear plant — 20 years;
Other generation — 20 years;
Transmission — 38 years;
Distribution — 34 years; and
General plant — 7 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. For the years 2018 through 2020, the depreciation rates ranged from a low of 0.18% to a high of 32.43%.  The weighted-average depreciation rate was 2.84% in 2020, 2.81% in 2019, and 2.81% in 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.  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.
 
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 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 13 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 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 either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  (See Note 16 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, 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 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 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 Note 5 for additional discussion.)
 
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
—  —  68,907 

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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 

Intangible Assets
 
We have no goodwill recorded and have separately disclosed other intangible assets, primarily 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.  Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2021, $56 million in 2022, $48 million in 2023, $33 million in 2024, and $25 million in 2025.  At December 31, 2020, the weighted-average remaining amortization period for intangible assets was 7 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 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 accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. (See Notes 13 and 19 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, 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 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 

(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).

Retail Electric Revenue. Pinnacle West’s retail electric revenue is generated by our wholly owned regulated subsidiary 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’ 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’ energy requirements. We may also sell 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 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, 2020 and 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 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

In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC 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”) 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 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 application 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”);
authorization to defer until 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 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 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” 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 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 commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.

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 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 Settlement 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 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”) 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
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 Rate Case 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”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. 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 adopted the Administrative Law 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. 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 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;
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 filed its rate case on October 31, 2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review 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 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 carrying costs for this program will be recovered through the RES.

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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 2021 RES Implementation Plan.

On July 15, 2020, ACC Staff issued final draft rules which, if approved, would require APS to meet certain clean energy standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a 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”) annually for review by and approval of the ACC. Verified energy savings from 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 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 sought a requested budget of $52.6 million and 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.

On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.

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

The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised of a forward component of $0.000536 per kWh and a 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 of $(0.002086) per kWh and a 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 two energy storage power purchase tolling agreements through the PSA. On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this application.

Environmental Improvement Surcharge (“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 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, 2021 application requested an increase in the charge to $10.3 million, or $1.5 million over the charge in effect for the 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 retail customers (“Retail Transmission 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 rate case (“2012 Settlement 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 actual cost of service, as disclosed in 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.

Effective June 1, 2018, 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 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 $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 are currently 2.5 cents for both lost residential and non-residential 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 filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR 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 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”).  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 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”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in 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. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of APS’s 2019 pending rate case. On December 9, 2020, the 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

APS’s 2017 Rate Case 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 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.

In addition, the ACC made the following determinations:

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 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 with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
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”) sought rehearing of the 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 Retail Rate Case Filing with the Arizona Corporation 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, 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.

On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS’s obligations to comply with the subpoenas and decline to decide 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 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, 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, 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, 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 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 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, 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 Burns’ amended complaint. On March 6, 2018, 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 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. 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, Burns filed a notice of appeal. On July 12, 2019, 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 given the COVID-19 pandemic.  The court determined that the matter could be submitted without oral argument and has 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.

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 CEO, Mr. Guldner, appeared at the ACC’s January 14, 2020 Open Meeting regarding ACC 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.

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
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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 an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020. 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. A new energy efficiency standard was not included in the proposed rules. APS would be required to 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 require utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.

The ACC has discussed the final draft energy rules at several different meetings in 2020. 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 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 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.

Integrated Resource Planning

ACC rules require utilities to develop 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.  The ACC reviews each utility’s IRP to determine if it meets the necessary 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

Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to qualifying facilities 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 two 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 June 1 through October 15 (“Summer Disconnection Moratorium”). During the 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. Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2021 and 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 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 waive late payment fees until October 15, 2021. The Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the 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 issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore the retail electric competition rules. 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 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 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 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 did not have a material impact on 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 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 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 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.

Four Corners 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 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 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 plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it 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 decommissioning and other retirement-related costs ($57 million as of December 31, 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.
Navajo Plant
The Navajo Plant ceased operations in 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.

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 ($72 million as of December 31, 2020) plus a return on the net book value as well as other costs related to retirement and closure, 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 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 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) $ —  $ 469,953  $ —  $ 660,223 
Deferred fuel and purchased power (b) (c) 2021 175,835  —  70,137  — 
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 —  95,723  —  38,144 
SCR deferral N/A —  81,307  —  52,644 
Deferred property taxes 2027 8,569  49,626  8,569  58,196 
Lost fixed cost recovery (b) 2021 41,807  —  26,067  — 
Deferred compensation 2036 —  36,195  —  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 —  21,255  —  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 —  7,268  —  — 
Tax expense adjustor mechanism (b) 2021 6,226  —  1,612  — 
Tax expense of Medicare subsidy 2024 1,235  3,704  1,235  4,940 
PSA interest 2021 4,355  —  1,917  — 
TCA balancing account (b) 2021 —  —  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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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 —  506,049  —  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 —  13,856  —  7,046 
Demand side management (b) 2021 10,819  —  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  —  — 
Tax expense adjustor mechanism (b) (e) 2021 7,089  —  7,018  — 
Active union medical trust N/A —  6,057  —  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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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.
    
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 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 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. The Company recorded $14 million and $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax 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. The Company recorded $31 million and $62 million of income tax benefit related to amortization of these depreciation related 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.

In September 2020, U.S. Treasury issued 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 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 continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. These final regulations do not materially impact any tax position taken by the Company for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.
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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 Statements of Income.
 
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. (See Note 18 for additional details related to the Palo Verde sale leaseback VIEs.)

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 —  —  —  —  —  — 
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 

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
  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, 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 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)

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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
  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, 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 
The following chart compares pretax income at the 21% statutory federal income tax rate 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 —  —  7,879  —  —  — 
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 

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     The components of the net deferred income tax liability were as follows (dollars in thousands):
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, 2020, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $35 million, which first begin to expire in 2036 and state credit carryforwards net of federal benefit of $33 million, which first begin to expire in 2023. PNW Consolidated credit and loss carryforwards amount above has been reduced by $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.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2020 and 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) —  (169,000) (114,675) —  (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%

Pinnacle West

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.

APS
 
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 or commercial paper borrowings.

See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.

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Debt Provisions
 
On 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 Note 7 for additional long-term debt provisions.)
 
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, 2020 and 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% —  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) —  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   —  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) —  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 —  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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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
2021 $ —  $ — 
2022 —  — 
2023 —  — 
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, 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

Pinnacle West
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.

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.
 
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 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 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 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, 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.

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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 December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization from $5.9 billion to $7.5 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. (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 “HRA”) for the employees of Pinnacle West and its subsidiaries.  These plans provide medical and life 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 Note 13 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 are recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory 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 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 —  —  —  (37,575) (37,821) (37,842)
Net actuarial loss 34,612  42,584  32,082  —  —  — 
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)
 
The following table shows the plans’ changes in the benefit obligations and funded status (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  —  — 
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 

The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
As of December 31,
  2020 2019
Accumulated benefit obligation 171,672  169,091 
Fair value of plan assets —  — 
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The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefit obligation basis at December 31, 2020 and December 31, 2019, therefore the only pension plan with an accumulated 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 —  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 (dollars in thousands):
  Pension Plans Other Benefits Plans
  2020 2019 2020 2019
Noncurrent asset $ 165,861  $ —  $ 337,131  $ 90,570 
Current liability (15,700) (14,578) —  — 
Noncurrent liability (166,484) (280,185) —  — 
Net amount recognized $ (16,323) $ (294,763) $ 337,131  $ 90,570 
 
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2020 and 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 —  —  (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 
 

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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  %
 
(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 2021, we are assuming a 5.30% long-term rate of return for pension assets and 5.05% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs. 

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 funded status at year-end 2020, the target and actual allocation for the pension plan at December 31, 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  %

The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the 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.

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 17  %
Equities in emerging markets %
Alternative investments %
Total 28  %

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, 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, 2020:
Other Benefits Plans
Actual Allocation
Long-term fixed income assets 55  %
Return-generating assets 45  %
Total 100  %
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See Note 13 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 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 NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets.  As of December 31, 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’ underlying assets. The plan’s partnerships holdings relate to investments in high-yield fixed income 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, 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) —  —  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  —  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  —  4,019  6,900 
Total $ 519,382  $ 210,639  $ 107,473  $ 837,494 
(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.  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 any contributions over the next three years to
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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.
 
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 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 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 2020, $11 million for 2019, and $11 million for 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 2021 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three 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 Note 18 for a discussion of VIEs.)

On June 1, 2020 APS had two separate purchased power lease 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 lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease 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 —  3,804  3,804  —  4,385  4,385 
Total lease cost $ 190,242  $ 23,269  $ 213,511  $ 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 expense recognized in the Consolidated Statements of Income was $18 million in 2018, this amount does not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in 2018. In addition, contingent rents for purchased power lease contracts was $109 million in 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).

The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
December 31, 2020
Year Purchased Power Lease Contracts Land, Property & Equipment Leases Total
2021 $ 66,658  $ 14,455  $ 81,113 
2022 68,325  10,849  79,174 
2023 70,033  8,503  78,536 
2024 71,784  6,104  77,888 
2025 73,578  4,400  77,978 
Thereafter 36,760  37,314  74,074 
Total lease commitments 387,138  81,625  468,763 
Less imputed interest 14,375  18,267  32,642 
Total lease liabilities $ 372,763  $ 63,358  $ 436,121 
    
We recognize lease assets and liabilities upon lease commencement. At December 31, 2020, we have certain purchased power lease contracts, that have been executed but have not yet commenced. In January 2021, we also executed additional purchased power lease contracts relating to energy storage. These arrangements have commencement dates beginning in May 2021 with terms ending through December 2042. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $650 million over the term of the arrangements.

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The following tables provide other additional information related to operating lease 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, 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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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, 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  — 
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  — 
Cholla 500kV Switchyard 85.7  % 7,896  1,850  940 
Saguaro 500kV Switchyard 60.0  % 21,669  13,229 
Kyrene — Knox System 50.0  % 578  323  — 
(a)See Note 18.
(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. 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 United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal 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”) 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 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 six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019. The DOE has approved and paid $99.7 million for these claims (APS’s share is $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 November 2, 2020, APS filed its seventh claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $12.2 million (APS’s share is $3.6 million).

Nuclear Insurance
 
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson 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 $13.8 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”).  The remaining balance of approximately $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 Palo Verde units, APS’s maximum retrospective premium per incident for all three 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 three units. The property damage,
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decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“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 policies totals approximately $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 $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 2021 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $772 million in 2021; $671 million in 2022; $632 million in 2023; $592 million in 2024; $564 million in 2025; and $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,
  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 $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,
  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 $35 million in 2021; $31 million in 2022; $30 million in 2023; $28 million in 2024; $25 million in 2025; and $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. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $16 million in 2021; $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; and $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 (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“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 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
 
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  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
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vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the 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 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 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 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC purchased the interest from 4CA on July 3, 2018. See “Four Corners — 4CA Matter” 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. In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements. In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025. PacifiCorp retired Cholla Unit 4 at the end of 2020. (See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset).
 
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”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:
Following the passage of the Water Infrastructure Improvements for the Nation 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 July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments; such disposal units must close as soon as technically feasible, but no later than April 22, 2021.
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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 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 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 on November 30, 2020 and is currently pending. This application will be subject to 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 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 $27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. 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.

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 such rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to
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EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.

Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, 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.
 
Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board (“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised 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. Based upon a November 1, 2019 filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit. Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. 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 these appeal proceedings and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.

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Four Corners

    4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC purchased this 7% interest on 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 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.
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 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, 2020, standby letters of credit totaled $5.2 million and will expire in 2021. As of December 31, 2020, surety bonds expiring through 2022 totaled $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, 2020. In connection with the sale of 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 Corners — 4CA 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 make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. The Equity Contribution Guarantees remaining as of December 31, 2020 are immaterial in amount (approximately $3 million) and the PTC Guarantees (approximately $39 million as of December 31, 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.

The following table shows the change in our asset retirement obligations for 2020 and 2019 (dollars in thousands):

  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.    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 — 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, 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 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 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. 
 
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds
 
The nuclear decommissioning 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 account. (See Note 19 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 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 equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds’ NAV as a practical expedient. The 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’ 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.

The 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 $ —  $ 9,016  $ $ (4,271) (a) $ 4,749 
Nuclear decommissioning trust:
Equity securities 29,796  —  —  (17,828) (b) 11,968 
U.S. commingled equity funds —  —  —  610,055  (c) 610,055 
U.S. Treasury debt 164,514  —  —  —  164,514 
Corporate debt —  149,509  —  —  149,509 
Mortgage-backed securities —  99,623  —  —  99,623 
Municipal bonds —  89,705  —  —  89,705 
Other fixed income —  13,061  —  —  13,061 
Subtotal nuclear decommissioning trust 194,310  351,898  —  592,227  1,138,435 
Other special use funds:
Equity securities 37,337  —  —  504  (b) 37,841 
U.S. Treasury debt 203,220  —  —  —  203,220 
Municipal bonds —  13,448  —  —  13,448 
Subtotal other special use funds 240,557  13,448  —  504  254,509 
Total assets $ 434,867  $ 374,362  $ $ 588,460  $ 1,397,693 
Liabilities
Risk management activities — derivative instruments:
Commodity contracts $ —  $ (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 $ —  $ 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.
(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, 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 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.
 
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 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 $27.1 million as of December 31, 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 Note 11 for more information on 4CA matters.)


 
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14.    Earnings Per Share
 
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (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 

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, 2020, 1.5 million common shares were available for issuance under the 2012 Plan. During 2020, 2019, and 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.  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.

As of December 31, 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.
 
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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 and 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 
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.
(b)Reflects the target payout level.
 
The following table is a summary of the status of non-vested awards as of December 31, 2020 and changes during the year:

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
Nonvested at January 1, 2020 242,612  $ 81.38  306,970  $ 83.65 
Granted 118,403  71.70  122,830  104.74 
Vested (136,893) 73.80  (161,906) 76.53 
Forfeited (c) (3,565) 82.61  (7,890) 85.06 
Nonvested at December 31, 2020 220,557  (a) 77.93  260,004  98.28 
Vested Awards Outstanding at December 31, 2020 82,921  161,906 
 
(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 $6 million, $5 million and $4 million in 2020, 2019 and 2018, respectively. This includes cash used to settle restricted stock units of $4 million, $5 million and $5 million in 2020, 2019 and 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 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.

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 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 two 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 total shareholder return (“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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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 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 Note 13 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.

The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
 
Quantity
Commodity Unit of Measure December 31, 2020 December 31, 2019
Power GWh 368  193 
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 (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, we had no gains or 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 no amounts will be reclassified from accumulated OCI into income.  For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.
 
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):
Financial Statement  Year Ended
December 31,
Commodity Contracts Location 2020 2019 2018
Net Loss Recognized in Income Operating revenues $ —  $ —  $ (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.
 
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 current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default.  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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The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of 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  $ —  $ 2,931 
Investments and other assets 3,150  (1,332) 1,818  —  1,818 
Total assets 9,020  (4,271) 4,749  —  4,749 
Current liabilities (9,211) 2,939  (6,272) (1,285) (7,557)
Deferred credits and other (12,394) 1,332  (11,062) —  (11,062)
Total liabilities (21,605) 4,271  (17,334) (1,285) (18,619)
Total $ (12,585) $ —  $ (12,585) $ (1,285) $ (13,870)
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No 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) —  (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.
(b)No 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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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, 2020, we have four counterparties for which our exposure represents approximately 62% of Pinnacle 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).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands):
  December 31, 2020
Aggregate fair value of derivative instruments in a net liability position $ 21,605 
Cash collateral posted — 
Additional cash collateral in the 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 $90 million if our debt credit ratings were to fall below investment grade.

 
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17.    Other Income and Other Expense
 
The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2020, 2019 and 2018 (dollars in thousands):
 
  2020 2019 2018
Other income:      
Interest income $ 12,210  $ 10,377  $ 8,647 
Investment gains (losses) — net 2,358  —  — 
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  — 
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 —  (1,835) (417)
Miscellaneous (45,376) (a) (5,382) (7,473)
Total other expense $ (57,776) $ (17,880) $ (17,966)
 
(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).

Other Income and Other Expense - APS
 
The following table provides detail of APS’s other income and other expense for 2020, 2019 and 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  — 
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)

(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).


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18.    Palo Verde Sale Leaseback Variable Interest Entities
 
In 1986, APS entered into agreements with three 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 one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 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’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the 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 and 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 include the following amounts relating to the VIEs (dollars in thousands):
  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.
 
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 $306 million beginning in 2021, and up to $456 million over the lease extension 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.
 
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 Note 13 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 — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo 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 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 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 may be used to pay active union employee medical costs incurred in the current and future periods. In 2020 and 2019, 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 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).

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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 nuclear decommissioning trust and other special use fund assets at December 31, 2020 and December 31, 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  $ — 
Available for Sale-Fixed Income Securities 516,412  216,668  733,080  (a) 46,581  (398)
Other (17,828) 504  (17,324) (b) —  — 
Total $ 1,138,435  $ 254,509  $ 1,392,944  $ 468,247  $ (398)
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.
(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  $ — 
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, 2019, the amortized cost basis of these available-for-sale investments is $691 million.
(b)Represents net pending securities sales and purchases.

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The following table sets forth 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 and 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) —  (6,972)
Proceeds from the sale of securities (a) 473,806  245,228  719,034 
2018
Realized gains 6,679  6,680 
Realized losses (13,552) —  (13,552)
Proceeds from the sale of securities (a) 554,385  98,648  653,033 
(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, 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  $ —  $ 52,642 
1 year – 5 years 151,537  29,722  142,311  323,570 
5 years – 10 years 133,307  2,738  —  136,045 
Greater than 10 years 212,005  8,818  —  220,823 
Total $ 516,412  $ 74,357  $ 142,311  $ 733,080 

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20.    Changes in Accumulated Other Comprehensive Loss
 
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 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) —  (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)
(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 consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 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) —  (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) $ —  $ (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).
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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,
  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.


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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(dollars in thousands)
 
  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 —  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)
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.
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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,
  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  —  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) —  — 
Common stock equity issuance — net of purchases (1,389) 692  (5,055)
Other —  —  (1)
Net cash flow used for financing activities (250,691) (290,676) (182,948)
Net decrease in cash and cash equivalents —  (22) — 
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.

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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.
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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, 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, 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, 2020 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.

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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 19, 2021 (the “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 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 2021 Proxy Statement.

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 2021 Proxy Statement.

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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 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 2020 2019
Audit Fees (1) $ 2,414,909  $ 2,328,565 
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 2020 and 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 $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 2020 were pre-approved by the Audit Committee or the Chair consistent with the pre-approval policy.

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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
3.1   Pinnacle West   3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962   8/7/2008
3.2   Pinnacle West   3.1 to Pinnacle West/APS February 25, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473   2/25/2020
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   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   3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473   2/20/2009
4.1   Pinnacle West   4.1 to Pinnacle West June 20, 2017 Form 8-K Report, File No. 1-8962
  6/20/2017
4.2   Pinnacle West
APS
  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
4.3   Pinnacle West
APS
  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
4.4   Pinnacle West   4.1 to Pinnacle West’s Registration Statement No. 333-52476   12/21/2000
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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
4.4a Pinnacle West 4.1 to Pinnacle West June 10, 2020 Form 8-K Report, File No. 1-8962 6/16/2020
4.5   Pinnacle West   4.2 to Pinnacle West’s Registration Statement No. 333-52476   12/21/2000
4.6   Pinnacle West
APS
  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
  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
  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
4.6c   APS   4.1 to APS’s July 31, 2006 Form 8-K Report, File No. 1-4473   8/3/2006
4.6d   Pinnacle West
APS
  4.6f to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/20/2015
4.6e   Pinnacle West
APS
  4.6g to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/20/2015
4.6f   Pinnacle West
APS
  4.6h to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/20/2015
4.6g   Pinnacle West
APS
  4.6i to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/20/2015
4.6h Pinnacle West
APS
  4.1 to Pinnacle West/APS May 14, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473 5/19/2015
4.6i   Pinnacle West
APS
  4.1 to Pinnacle West/APS November 3, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473 11/6/2015
4.6j   Pinnacle West
APS
  4.1 to Pinnacle West/APS May 3, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473 5/6/2016
4.6k Pinnacle West
APS
  4.1 to Pinnacle West/APS September 15, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473 9/20/2016
4.6l Pinnacle West
APS
  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
Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
4.6m Pinnacle West
APS
  4.1 to Pinnacle West/APS August 9, 2018 Form 8-K Report, File Nos. 1-8962 and 1-4473 8/9/2018
4.6n Pinnacle West
APS
4.1 to Pinnacle West/APS February 28, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 2/28/2019
4.6o Pinnacle West
APS
4.1 to Pinnacle West/APS August 16, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 8/16/2019
4.6p Pinnacle West
APS
4.1 to Pinnacle West/APS November 20, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 11/20/2019
4.6q Pinnacle West
APS
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
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   4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962   8/9/2004
4.7a   Pinnacle West   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
4.8a   Pinnacle West
APS
  4.1 to APS’s 1993 Form 10-K Report, File No. 1-4473   3/30/1994
4.9 Pinnacle West
APS
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
  10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473   3/30/1995
10.1.1b   Pinnacle West
APS
  10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473   3/30/1995
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Table of Contents
Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.1.1c   Pinnacle West
APS
  10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473   3/28/1997
10.1.1d   Pinnacle West
APS
  10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473   3/28/1997
10.1.1e   Pinnacle West
APS
  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
  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
  10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962   3/15/2004
10.1.1h   Pinnacle West
APS
  10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962   3/15/2004
10.1.1i   Pinnacle West
APS
  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
  10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473   5/9/2007
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
  10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473   3/30/1995
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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.1.2c   Pinnacle West
APS
  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
  APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473   3/28/1997
10.1.2e   Pinnacle West
APS
  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
  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
  10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962   3/15/2004
10.1.2h   Pinnacle West
APS
  10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962   2/27/2008
10.2.1b
  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
10.2.1ab
  Pinnacle West
APS
  10.3A to APS’s 1993 Form 10-K Report, File No. 1-4473   3/30/1994
10.2.1bb
  Pinnacle West
APS
  10.2 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473   11/10/1994
10.2.1cb
  Pinnacle West
APS
  10.3A to APS’s 1996 Form 10-K Report, File No. 1-4473   3/28/1997
10.2.1db
  Pinnacle West
APS
  10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962   3/14/2001
10.2.2b
  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
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Table of Contents
Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.2.2ab
  Pinnacle West
APS
  10.2A to APS’s 1993 Form 10-K Report, File No. 1-4473   3/30/1994
10.2.2bb
  Pinnacle West
APS
  10.1 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473   11/10/1994
10.2.2cb
  Pinnacle West
APS
  10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962   3/30/2000
10.2.3b
  Pinnacle West
APS
  10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962   3/30/2000
10.2.3ab
  Pinnacle West
APS
  10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962   3/30/2000
10.2.4b
  Pinnacle West
APS
  10.10A to APS’s 1995 Form  10-K Report, File No. 1-4473   3/29/1996
10.2.4ab
  Pinnacle West
APS
10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 3/30/2000
10.2.4bb
  Pinnacle West
APS
10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 3/30/2000
10.2.4cb
  Pinnacle West
APS
10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962 5/15/2003
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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.2.4db
  Pinnacle West
APS
  10.64b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473   3/13/2006
10.2.5b
  Pinnacle West
APS
  10.2.5 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/19/2016
10.3.1b
  Pinnacle West
APS
  10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962   3/15/2004
10.3.1ab
  Pinnacle West
APS
  10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473   3/13/2006
10.3.2b
  Pinnacle West
APS
  10.3.2 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/19/2016
10.3.2ab
  Pinnacle West
APS
10.3.2a to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/24/2017
10.3.2bb
  Pinnacle West
APS
10.3.2b to Pinnacle West/APS 2017 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/23/2018
10.4.1b
  Pinnacle West
APS
  10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473   8/7/2008
10.4.2b
Pinnacle West
APS
10.4.5 to Pinnacle West/APS 2019 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/21/2020
10.4.3b
Pinnacle West
APS
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
10.4.5ab
Pinnacle West
APS
201

Table of Contents
Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.4.5bb
Pinnacle West
APS
10.4.6b
Pinnacle West
APS
10.4.7b
Pinnacle West
APS
10.4.8b
Pinnacle West
APS
10.5.1bd
  Pinnacle West
APS
  10.77bd to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473   3/13/2006
10.5.1abd
  Pinnacle West
APS
  10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473   11/6/2007
10.5.2bd
  Pinnacle West
APS
  10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473   11/6/2007
10.5.3bd
  Pinnacle West
APS
  10.5.3 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473   2/19/2010
10.5.4bd
  Pinnacle West
APS
  10.5.4 to Pinnacle West/APS 2012 Form 10-K, File Nos. 1-8962 and 1-4473   2/22/2013
10.6.1b
  Pinnacle West   Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962   4/20/2007
10.6.1ab
  Pinnacle West   10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962   4/20/2007
10.6.1bbd
  Pinnacle West
APS
  10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/5/2009
10.6.1cbd
  Pinnacle West   10.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962   8/3/2010
10.6.1dbd
  Pinnacle West   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
Previously Filed as Exhibit: a
  Date Filed
10.6.1ebd
  Pinnacle West   10.4 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962   4/29/2011
10.6.1fbd
  Pinnacle West   10.5 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962   4/29/2011
10.6.1gbd
  Pinnacle West   10.6 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962   4/29/2011
10.6.2b
  Pinnacle West   10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962   11/6/2007
10.6.3b
  Pinnacle West   10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962   8/7/2008
10.6.4bd
  Pinnacle West
APS
       
10.6.5b
  Pinnacle West
APS
  Appendix A to the Proxy Statement for Pinnacle West’s 2012 Annual Meeting of Shareholders, File No. 1-8962   3/29/2012
10.6.5abd
  Pinnacle West   10.1 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/3/2012
10.6.5bbd
  Pinnacle West   10.2 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/3/2012
10.6.5cbd
  Pinnacle West   10.6.8c to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473   2/21/2014
10.6.5dbd
  Pinnacle West   10.6.8d to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473   2/21/2014
10.6.5ebd
  Pinnacle West   10.6.6e to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/19/2016
10.6.5fbd
  Pinnacle West   10.6.6f to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/24/2017
203

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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.6.5gbd
  Pinnacle West   10.6.6g to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 2/24/2017
10.6.5hbd
  Pinnacle West   10.2 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 5/1/2019
10.6.5ibd
  Pinnacle West   10.3 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 5/1/2019
10.6.5jbd
Pinnacle West 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
10.6.5lbd
Pinnacle West
10.6.5mbd
  Pinnacle West   10.3 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/3/2012
10.6.5nbd
  Pinnacle West   10.4 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/3/2012
10.6.5obd
Pinnacle West 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 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
  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
  10.2 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473   4/29/2011
204

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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
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
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
  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
  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
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
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
  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
  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
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
  10.3 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
10.10.3   Pinnacle West
APS
  10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473   3/29/1996
10.10.4   Pinnacle West
APS
  10.5 to APS’s 1995 Form 10-K Report, File No. 1-4473   3/29/1996
10.10.5   Pinnacle West
APS
  10.6 to APS’s 1995 Form 10-K Report, File No. 1-4473   3/29/1996
10.11.1   Pinnacle West APS 10.1 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 5/1/2019
10.11.2 Pinnacle West 10.3 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473 8/3/2018
10.11.3   Pinnacle West   10.2 to Pinnacle West/APS March 31, 2020 Form 10-Q Report, File Nos. 1-8962 and 1-4473   5/8/2020
10.11.4   Pinnacle West
APS
  10.2 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473   8/3/2017
10.11.4a   Pinnacle West
APS
10.11.4a to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473   8/3/2018
10.11.5 Pinnacle West
APS

10.4 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473 8/3/2018
10.12.1c
  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

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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.12.1ac
  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
10.12.1bc
  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
10.12.1cc
  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
10.12.1dc
  Pinnacle West
APS
  10.2 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473   10/30/2015
10.12.1ec
  Pinnacle West
APS
  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

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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
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
  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
  10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473   3/16/2005
10.13.3   Pinnacle West
APS
  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
  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
  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

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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
10.15.1   Pinnacle West
APS
  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
  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
  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
  10.2 to APS’s May 19, 1998 Form 8-K Report, File No. 1-4473   6/26/1998
10.16   Pinnacle West
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
  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
  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 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        
23.1   Pinnacle West        
23.2   APS        
31.1   Pinnacle West        
31.2   Pinnacle West        
31.3   APS        
31.4   APS        
210

Table of Contents
Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
32.1e
  Pinnacle West        
32.2e
  APS        
99.1c
  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
99.1ac
  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
99.1bc
  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
99.2c
  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

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Exhibit
No.
  Registrant(s)   Description
Previously Filed as Exhibit: a
  Date Filed
99.2ac
  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
99.2bc
  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
99.3c
  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
99.3ac
  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
99.3bc
  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
99.4   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

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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
99.4b   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
99.5   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
99.5a   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
99.5b   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
99.6   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
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
99.7c
  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
99.8   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
99.9   Pinnacle West
APS
  10.2 to APS’s September 30, 1999 Form 10-Q Report, File No. 1-4473   11/15/1999
99.10   Pinnacle West   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.
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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)
Date: February 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
/s/ Jeffrey B. Guldner Principal Executive Officer February 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 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 24, 2021
(Denis A. Cortese, M.D.)
/s/ Richard P. Fox Director February 24, 2021
(Richard P. Fox)
/s/ Dale E. Klein, Ph.D. Director February 24, 2021
(Dale E. Klein, Ph.D.)
/s/ Humberto S. Lopez Director February 24, 2021
(Humberto S. Lopez)
/s/ Kathryn L. Munro Director February 24, 2021
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom Director February 24, 2021
(Bruce J. Nordstrom)
/s/ Paula J. Sims Director February 24, 2021
(Paula J. Sims)
/s/ James E. Trevathan Director February 24, 2021
(James E. Trevathan)
/s/ David P. Wagener Director February 24, 2021
(David P. Wagener)
216

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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.
 
  ARIZONA PUBLIC SERVICE COMPANY
  (Registrant)
   
   
 Date: February 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.
 
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
         
       
/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

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/s/ Glynis A. Bryan Director February 24, 2021
(Glynis A. Bryan)
/s/ Denis A. Cortese, M.D.   Director   February 24, 2021
(Denis A. Cortese, M.D.)        
       
/s/ Richard P. Fox   Director   February 24, 2021
(Richard P. Fox)        
       
       
/s/ Dale E. Klein, Ph.D.   Director   February 24, 2021
(Dale E. Klein, Ph.D.)        
       
       
/s/ Humberto S. Lopez   Director   February 24, 2021
(Humberto S. Lopez)        
       
       
/s/ Kathryn L. Munro   Director   February 24, 2021
(Kathryn L. Munro)        
       
       
/s/ Bruce J. Nordstrom   Director   February 24, 2021
(Bruce J. Nordstrom)        
       
/s/ Paula J. Sims Director February 24, 2021
(Paula J. Sims)
/s/ James E. Trevathan Director February 24, 2021
(James E. Trevathan)
/s/ David P. Wagener   Director   February 24, 2021
(David P. Wagener)        

218

DESCRIPTION OF THE REGISTRANTS’ SECURITIES
REGISTERED PURSUANT TO SECTION 12 OF THE
SECURITIES EXCHANGE ACT OF 1934

Pinnacle West Capital Corporation (“Pinnacle West”)

The following description of Pinnacle West’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 is a summary and does not purport to be complete. The description is subject to, and qualified in its entirety by express reference to, the provisions of Pinnacle West’s articles of incorporation and bylaws. Copies of the articles of incorporation and bylaws have been filed by Pinnacle West with the Securities and Exchange Commission and are exhibits to our Annual Report on Form 10-K to which this Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 is an exhibit. When we use the terms "we," "us," "our," and like terms in this description of Pinnacle West securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, we are referring to Pinnacle West.
Authorized Shares
Under our articles of incorporation, we have the authority to issue 150,000,000 shares of common stock. Our Board of Directors has significant discretion to determine the timing, circumstances and purposes for which the authorized shares of common stock available for issuance under our articles of incorporation may be issued, including in the context of acquisitions or other strategic transactions.
Dividends
Subject to any preferential rights of any series of preferred stock, holders of shares of common stock will be entitled to receive dividends on the stock out of assets legally available for distribution when, as and if declared by our Board of Directors. The payment of dividends on the common stock will be a business decision to be made by our Board of Directors from time to time based upon results of our operations and our financial condition and any other factors that our Board of Directors considers relevant. Payment of dividends on the common stock may be restricted by loan agreements, indentures and other transactions entered into by us from time to time. Any material contractual restrictions on dividend payments that exist at the time of any offer of any common stock will be described in the applicable offering documents. In addition, our principal income consists of dividends paid to us by our subsidiaries, primarily Arizona Public Service Company (“APS”). APS's ability to pay dividends could be limited or restricted from time to time by loan agreements, indentures and other transactions or by law or regulatory authorities.
Voting Rights
Holders of common stock are entitled to one vote per share on all matters voted on generally by the shareholders. Arizona law provides for cumulative voting for the election of directors. As a result, any shareholder may cumulate his or her votes by casting them all for any one director nominee or by distributing them among two or more nominees. This may make it easier for minority shareholders to elect a director.




Liquidation Rights
Subject to any preferential rights of any series of preferred stock, holders of shares of common stock are entitled to share ratably in our assets legally available for distribution to our shareholders in the event of our liquidation, dissolution or winding up.
Absence of Other Rights or Assessments
Holders of common stock have no preferential, preemptive, conversion or exchange rights. When issued in accordance with our articles of incorporation and law, shares of our common stock will be fully paid and not liable to further calls or assessment by us.
Transfer Agent and Registrar
Computershare Trust Company, N. A. is the transfer agent and registrar for the common stock.
Preferred Stock
Our Board of Directors has the authority, without any further action by our shareholders, to issue from time to time up to 10,000,000 shares of preferred stock, in one or more series, and to fix the designations, preferences, rights, qualifications, limitations and restrictions thereof, including voting rights, dividend rights, dividend rates, conversion rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series. The issuance of preferred stock with voting rights could have an adverse effect on the voting power of holders of common stock by increasing the number of outstanding shares having voting rights. In addition, if our Board of Directors authorizes preferred stock with conversion rights, the number of shares of common stock outstanding could potentially be increased up to the authorized amount. The issuance of preferred stock could decrease the amount of earnings and assets available for distribution to holders of common stock. Any such issuance could also have the effect of delaying, deterring or preventing a change in control of us.
Certain Anti-takeover Effects
General.    Certain provisions of our articles of incorporation, our bylaws, and Arizona law may have an anti-takeover effect and may delay or prevent a tender offer or other acquisition transaction that a shareholder might consider to be in his or her best interest. The summary of the provisions of our articles, bylaws and Arizona law set forth below does not purport to be complete and is qualified in its entirety by reference to our articles, bylaws and Arizona law.
Business Combinations.    Arizona law and our bylaws restrict a wide range of transactions (collectively, "business combinations") between us or, in certain cases, one of our subsidiaries, and an interested shareholder. An "interested shareholder" is:
• any person who beneficially owns, directly or indirectly, 10% or more of our outstanding voting power, or
• any of our affiliates or associates who at any time within the prior three years was such a beneficial owner.
The statute defines "business combinations" to include, with certain exceptions:
• mergers, consolidations and share exchanges with an interested shareholder;



• any sale, lease, exchange, mortgage, pledge, transfer or other disposition of assets to an interested shareholder, representing 10% or more of (i) the aggregate market value of all of our consolidated assets as of the end of the most recent fiscal quarter, (ii) the aggregate market value of all our outstanding shares, or (iii) our consolidated revenues or net income for the four most recent fiscal quarters;
• the issuance or transfer of shares of stock having an aggregate market value of 5% or more of the aggregate market value of all of our outstanding shares to an interested shareholder;
• the adoption of a plan or proposal for our liquidation or dissolution or reincorporation in another state or jurisdiction pursuant to an agreement or arrangement with an interested shareholder;
• corporate actions, such as stock splits and stock dividends, and other transactions, in each case resulting in an increase in the proportionate share of the outstanding shares of any series or class of stock of us or any of our subsidiaries owned by an interested shareholder; and
• the receipt by an interested shareholder of the benefit (other than proportionately as a shareholder) of any loans, advances, guarantees, pledges or other financial assistance or any tax credits or other tax advantages provided by or through us or any of our subsidiaries.
Arizona law and our bylaws provide that, subject to certain exceptions, we may not engage in a business combination with an interested shareholder or authorize one of our subsidiaries to do so, for a period of three years after the date on which the interested shareholder first acquired the shares that qualify such person as an interested shareholder (the "share acquisition date"), unless either the business combination or the interested shareholder's acquisition of shares on the share acquisition date is approved by a committee of our Board of Directors (comprised solely of disinterested directors or other disinterested persons) prior to the interested shareholder's share acquisition date.
In addition, after such three-year period, Arizona law and our bylaws prohibit us from engaging in any business combination with an interested shareholder, subject to certain exceptions, unless:
• the business combination or acquisition of shares by the interested shareholder on the share acquisition date was approved by our Board of Directors prior to the share acquisition date;
• the business combination is approved by holders of a majority of our outstanding shares (excluding shares beneficially owned by the interested shareholder) at a meeting called after such three-year period; or
• the business combination satisfies specified price and other requirements.
Anti-Greenmail Provisions.    Arizona law and our bylaws prohibit us from purchasing any shares of our voting stock from any beneficial owner (or group of beneficial owners acting together) of more than 5% of the voting power of our outstanding shares at a price per share in excess of the average closing sale price during the 30 trading days preceding the purchase or if the person or persons have commenced a tender offer or announced an intention to seek control of us, during the 30 trading days prior to the commencement of the tender offer or the making of the announcement, if the 5% beneficial



owner has beneficially owned the shares to be purchased for a period of less than three years, unless:
• holders of a majority of our voting power (excluding shares held by the 5% beneficial owner or by any of our officers and directors) approve the purchase; or
• we make the repurchase offer available to all holders of the class or series of securities to be purchased and to all holders of other securities convertible into that class or series.
Control Share Acquisition Statute.    Under Arizona law, a control share acquisition is an acquisition, subject to certain exceptions, by a beneficial owner that would result in the owner having a new range of voting power within any of the following ranges: (i) at least 20% but less than 331/3%; (ii) at least 331/3% but less than or equal to 50%; or (iii) more than 50%. Through a provision in our bylaws, we have opted out of the Arizona statutory provisions regulating control share acquisitions. As a result, potential acquirors are not subject to the limitations imposed by that statute.
Special Meetings of Shareholders.    Our bylaws provide that, except as required by law, special meetings of shareholders may be called by a majority of our Board of Directors, the Chairman of the Board, the President, or shareholders who have continuously held of record for at least one year Net Long Shares (as described in Section 2.02 of the bylaws) in the aggregate at least 15% of the voting power of the outstanding capital stock of Pinnacle West ("Special Meeting Requesting Shareholders"). Special Meeting Requesting Shareholders must meet certain qualifications and must submit a written request to the Corporate Secretary, containing the information required by our bylaws. A request for a special meeting made by Special Meeting Requesting Shareholders may be rejected if: (1) a meeting of shareholders that included an identical or substantially similar item of business, as determined in good faith by our Board of Directors, was held not more than 90 days before the Corporate Secretary received the request; (2) our Board of Directors has called or calls for a meeting of shareholders to be held within 90 days after the Corporate Secretary receives the request and our Board of Directors determines in good faith that the business to be conducted at such meeting includes similar business to that stated in the request; or (3) the request relates to an item of business that is not a proper subject for shareholder action under, or involves a
Election and Removal of Directors.    Each member of our Board of Directors is elected annually to hold office until the next annual meeting of the shareholders or until his or her earlier death, resignation or removal or until his or her successor is duly elected and qualified.
     Our bylaws provide that any director or the entire Board of Directors may be removed by vote of the shareholders with or without cause, but only at a special meeting called for that purpose, if the votes cast in favor of such removal exceed the votes cast against such removal. However, if less than the entire Board of Directors is to be removed, no one director may be removed if the votes cast against the director's removal would be sufficient to elect the director if then cumulatively voted at an election of directors.
Our bylaws provide that a director in an uncontested election who receives a greater number of votes cast "withheld" for his or her election than "for" such election must tender his or her resignation to the Corporate Governance Committee of our Board of Directors for



consideration. The Corporate Governance Committee will evaluate the director's tendered resignation, taking into account the best interest of Pinnacle West and its shareholders and will recommend to our Board of Directors whether to accept or reject the resignation. Any director tendering a resignation pursuant to this provision of our bylaws will not participate in any committee or Board of Director consideration of his or her resignation.
Our bylaws grant our Board of Directors the exclusive power to increase the size of our Board of Directors. Any such increase in the size of our Board of Directors, and the filling of any vacancy created thereby, require action by a majority of the whole membership of our Board of Directors as comprised immediately before such increase.
Shareholder Proposals and Director Nominations.    A shareholder can submit shareholder proposals and nominate candidates for election to our Board of Directors in connection with our annual meeting if he or she follows the advance notice and other relevant provisions set forth in our bylaws. With respect to director nominations at an annual meeting not included in our proxy materials, shareholders must satisfy the provisions set forth in our bylaws and submit written notice to the Corporate Secretary at least 180 days prior to the date of the meeting. With respect to director nominations at an annual meeting to be included in our proxy materials, shareholders must satisfy the provisions set forth in our bylaws and submit such nomination to the Corporate Secretary not fewer than 120 nor more than 150 days prior to the first anniversary of the date that we mailed our proxy statement for the prior year's annual meeting of shareholders. With respect to shareholder proposals to bring other business before the annual meeting, shareholders must submit a written notice to the Corporate Secretary not fewer than 90 nor more than 120 days prior to the first anniversary of the date of our previous year's annual meeting of shareholders. However, if we have changed the date of the annual meeting by more than 30 days from the date of the previous year's annual meeting, the written notice must be submitted no earlier than 120 days before the annual meeting and not later than 90 days before the annual meeting or ten days after the day we make public the date of the annual meeting.
A shareholder must also comply with all applicable laws in proposing business to be conducted and in nominating directors. The notice provisions of the bylaws do not affect rights of shareholders to request inclusion of proposals in our proxy statement pursuant to Rule 14a-8 of the Exchange Act.
 Amendment to Articles of Incorporation and Bylaws.    Both the Board of Directors and the shareholders must approve amendments to an Arizona corporation's articles of incorporation, except that the Board of Directors may adopt specified ministerial amendments without shareholder approval. Unless the articles of incorporation, Arizona law or the Board of Directors would require a greater vote or unless the articles of incorporation or Arizona law would require a different quorum, the vote required by each voting group allowed or required to vote on the amendment would be:
• a majority of the votes entitled to be cast by the voting group, if the amendment would create dissenters' rights for that voting group; and
• in any other case, if a quorum is present in person or by proxy consisting of a majority of the votes entitled to be cast on the matter by the voting group, the votes cast by the voting group in favor of the amendment must exceed the votes cast against the amendment by the voting group.



The Board of Directors may amend or repeal the corporation's bylaws unless either: (i) the articles or applicable law reserves this power exclusively to shareholders in whole or in part or (ii) the shareholders in amending or repealing a particular bylaw provide expressly that the Board may not amend or repeal that bylaw. An Arizona corporation's shareholders may amend or repeal the corporation's bylaws even though they may also be amended or repealed by the Board of Directors. Our bylaws may not be amended or repealed without the vote of a majority of the Board of Directors then in office or the affirmative vote of a majority of votes cast on the matter at a meeting of shareholders.
Issuance of Additional Shares.    Our Board of Directors has the ability to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval. See the discussion above under the headings "Authorized Shares" and "Preferred Stock."




Arizona Public Service Company (“APS”)

The following description of APS’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 is a summary and does not purport to be complete. The description is subject to, and qualified in its entirety by express reference to, the provisions of APS’s articles of incorporation and bylaws. Copies of the articles of incorporation and bylaws have been filed by APS with the Securities and Exchange Commission and are exhibits to our Annual Report on Form 10-K to which this Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 is an exhibit. When we use the terms "we," "us," "our," and like terms in this description of APS securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, we are referring to APS.
General
The general terms and provisions of our common stock are summarized below. All of our outstanding common stock is held by Pinnacle West and we have no preferred stock outstanding. However, subject to certain limitations, our Board of Directors has the authority, without any further action by our shareholders, to issue from time to time shares of preferred stock, in one or more series and to fix the designations, preferences, rights, qualifications, limitations and restrictions thereof.
Authorized Shares
Under our articles of incorporation, we have the authority to issue 100,000,000 shares of common stock, par value $2.50 per share.
Dividends
     
Subject to any preferential rights of any series of preferred stock, holders of shares of common stock will be entitled to receive dividends on the stock out of assets legally available for distribution when, as and if authorized and declared by our Board of Directors. The payment of dividends on the common stock will be a business decision to be made by our Board of Directors from time to time based upon results of our operations and our financial condition and any other factors as our Board of Directors considers relevant. Payment of dividends on the common stock may be restricted by loan agreements, indentures and other transactions entered into by us from time to time. An Arizona Corporation Commission (“ACC”) order requires APS to maintain a common equity ratio of at least 42% and does not allow APS to pay dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.

Voting Rights

Except as specified below, holders of common stock and preferred stock are entitled to one vote for each share held of record. Arizona law provides for cumulative voting for the election of directors. If six or more quarterly dividends accrued thereon shall not have been paid with respect to any outstanding preferred stock, the holders of such preferred stock will



have the right to elect the lesser of six directors or one-fourth of the total number of members of the Board of Directors at the time, in addition to their other voting rights. The preferred stock will also have special voting rights in matters involving the preferences or privileges of the preferred stock and certain extraordinary corporate occurrences.

Liquidation Rights
Subject to any preferential rights of any series of preferred stock, holders of shares of common stock are entitled to share ratably in our assets legally available for distribution to our shareholders in the event of our liquidation, dissolution or winding up.

Pre-emptive Rights

The holders of common stock have no pre-emptive rights to subscribe for other shares except with respect to an offering of additional common stock, or securities convertible into common stock, for money, other than by (a) a public offering of all of such shares, (b) an offering of all of such shares to or through underwriters or investment bankers who shall have agreed promptly to make a public offering of such shares, or (c) an offering of all such shares to our stockholders, our employees or our customers.

Miscellaneous

Outstanding shares of our common stock are fully paid and not liable to further calls or assessment by us.





Discretionary Credit Award Agreement
This Discretionary Credit Award Agreement (the “Agreement”) is entered into by and between Arizona Public Service Company (“APS”) and Theodore Geisler (“Employee”).
1.Purpose. Section 3.9 of the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Deferred Compensation Plan”) allows APS to award Discretionary Credits in such amounts and subject to such terms and conditions as APS deems appropriate. The purpose of this Agreement is to award Discretionary Credits to Employee subject to the terms and conditions set forth below.
2.Definitions. A number of key terms, with specialized meanings, are used throughout this Agreement. These key terms are identified by the capitalization of the initial letter of each word or phrase even when the word or phrase does not begin a sentence. Each of these key terms will be given the meaning ascribed to it in the Deferred Compensation Plan unless the term is defined in this Agreement. Whenever these key terms are used, they will be given the defined meaning unless a clearly different meaning is required by the context.
3.Discretionary Credits. Five Discretionary Credits in the aggregate amount of $300,000 will be allocated to a Discretionary Credit Account (the “Discretionary Credit Account”) established for the benefit of Employee pursuant to Section 3.9 of the Deferred Compensation Plan. The Discretionary Credit Account shall be credited with: (i) $100,000 on July 1, 2019; and (ii) $50,000 on each of January 1, 2020 through January 1, 2023 provided that the Employee remains employed with APS on each such crediting date and demonstrates sustained competent performance of his assigned job responsibilities.
4.Interest. The Discretionary Credit Account shall be credited with interest in accordance with Section 3.5 of the Deferred Compensation Plan.
5.Vesting. The Discretionary Credit Account vests on December 31, 2024. If Employee Separates from Service prior to December 31, 2024, the amounts allocated to the Discretionary Credit Account will be forfeited; provided, however, that if Employee’s employment with APS is involuntarily terminated by APS without Cause, Employee dies or Employee becomes Disabled prior to December 31, 2024, all amounts previously credited to the Discretionary Credit Account will be fully vested as of the date of the termination by APS without Cause, death or Disability as applicable. For purposes of this document, “Disability” shall have the meaning ascribed to it in the Pinnacle West Capital Corporation Long-Term Disability Plan. For purposes of this document, “Cause” means any act or omission that could result in disciplinary action pursuant to applicable laws or APS policies and procedures, as determined in the sole discretion of APS. The determination of whether “Cause” exists shall be made by APS, in its sole and absolute discretion, in accordance with its personnel policies and procedures.





6.Payment of Discretionary Credits.
(a)General Rule. Except as otherwise provided below in this Section 6, Employee’s vested interest in his Discretionary Credit Account will be paid to Employee in substantially equal installments over a period of approximately five years following Employee’s Separation from Service with the first installment payment to made within 30 days following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date, unless Employee is a Specified Employee on the date of his Separation from Service. If Employee is a Specified Employee on the date of his Separation from Service, the first installment payment shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date. The Discretionary Credit Account may not be distributed as a ShortTerm Payout or due to an Unforeseeable Financial Emergency.
(b)Disability. If Employee becomes Disabled prior to his Separation from Service and if such Disability occurs prior to December 31, 2024, Employee shall receive a single lump sum payment of Employee’s vested interest in his Discretionary Credit Account on the first business day following December 31, 2024 as long as the Disability constitutes a “disability” as defined in Section 409A of the Code. If the Disability does not constitute a “disability” as defined in Section 409A of the Code, the general rule set forth in Section 6(a) will apply, unless Employee incurs a Separation from Service before December 31, 2024, in which case Employee shall receive a single lump sum payment of Employee’s vested interest in his Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of his Separation from Service. If Employee is a Specified Employee on the date of his Separation from Service, Employee’s vested interest in his Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
(c)Death. If Employee dies while employed by the Company, or after the commencement of installment payments as described in Section 6(a) but before all such payments have been made in full, the Beneficiary designated by Employee pursuant to the Deferred Compensation Plan shall receive a single lump sum payment of Employee’s vested interest in his Discretionary Credit Account within sixty days of Employee’s death.
(d)Termination without Cause. If Employee’s employment is terminated by the Company without cause and if, as a result of such termination, Employee incurs a Separation from Service before December 31, 2024, Employee shall receive a single lump sum payment of Employee’s vested interest in his Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of his Separation from Service. If Employee is a Specified Employee on the date of his Separation from Service, Employee’s vested interest in his Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
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7.Employee’s Plan Status. Regardless of whether Employee makes an Annual Deferral pursuant to the terms of the Deferred Compensation Plan for the relevant Plan Year, Employee shall be deemed to be a Participant in the Deferred Compensation Plan and to have elected to participate in the Deferred Compensation Plan for the limited purpose of receiving the Discretionary Credits described in this Agreement. This Agreement shall be deemed to be Employee’s Election Form for purposes of Section 2.2 and Section 3.3 of the Deferred Compensation Plan.
8.Relationship to Other Benefits. The Discretionary Credits allocated to Employee pursuant to this Agreement shall not be taken into account as compensation or for purposes of determining any benefits due to Employee pursuant to the terms of any pension, retirement, savings, profit sharing, incentive, group insurance or other tax qualified or nonqualified benefit plan sponsored by APS, Pinnacle West Capital Corporation or any affiliate of either. In addition, the amounts payable to Employee attributable to the Discretionary Credit Account established for Employee pursuant to the Deferred Compensation Plan shall be disregarded for purposes of the benefit plans referred to in the preceding sentence.
9.Plan Document. As provided above, this Agreement is entered into pursuant to the provisions of Section 3.9 of the Deferred Compensation Plan. Accordingly, except as otherwise set forth in this Agreement, the provisions of the Deferred Compensation Plan shall apply in determining the rights of Employee as well as the administration of Employee’s Discretionary Credit Account. In cases of conflict, this Agreement controls over any conflicting provisions of the Deferred Compensation Plan, except as may be required by Section 409A of the Internal Revenue Code or the provisions of any other applicable law or regulation.
10.Amendments. This Agreement may not be modified, altered or changed except by a written agreement signed by APS and Employee.
11.Confidentiality. Employee shall hold the existence and terms of this Agreement in confidence. Employee shall not publicly or privately discuss or disclose the nature or content of this Agreement. However, Employee may disclose the terms of this Agreement if required by federal or state law, and Employee may disclose the terms of this Agreement to Employee’s accountant, attorney, consultant and spouse. In addition, APS and Employee may disclose this Agreement as necessary to enforce its provisions.
12.Reporting to Federal and State Agencies. Nothing in this Agreement shall be construed to prohibit Employee from reporting or disclosing any suspected instance of illegal activity of any nature, any nuclear safety concerns, any workplace safety concerns, or any public safety concerns to the Nuclear Regulatory Commission (“NRC”), the United States Department of Labor (“DOL”), or any other federal, state, or local government agency or court. This Agreement shall not be construed to prohibit Employee from providing information to the NRC, DOL, Equal Employment Opportunity Commission, United States Securities and Exchange Commission, Occupational Safety and Health Administration, or Arizona Division of Occupational Safety and Health, or testifying in any civil or criminal proceedings, even if such information or testimony being provided relates to the claims or matters covered by this Agreement. This Agreement shall not be construed as a waiver or withdrawal of any safety
    3    


concerns which Employee has or may have reported to the NRC or DOL, or withdrawal of any participation by Employee in any NRC proceedings. In this regard, the parties to this Agreement understand that this Agreement shall be interpreted in a manner consistent with 10 CFR § 50.7(f). Notwithstanding anything to the contrary in this paragraph, Employee hereby waives and releases any right to receive any relief as a result of the Employee's participation in any investigation or proceeding of the NRC, DOL, or any federal, state, or local government agency or court.
13.Entire Agreement. APS and Employee acknowledge and agree that this Agreement and the Deferred Compensation Plan constitute the entire agreement between APS and Employee with respect to the subject matter hereof.
14.Severability. If any provision of this Agreement is held to be invalid, the remaining provisions shall remain in full force and effect.
IN WITNESS WHEREOF, APS and Employee have executed this Agreement on the dates set forth below.
ARIZONA PUBLIC SERVICE COMPANY



By: /s/ Donald E. Brandt                
Donald E. Brandt
Chairman and Chief Executive Officer

Date:    June 19, 2019                    


EMPLOYEE


/s/ Theodore Geisler                    
Theodore Geisler

Date:    June 19, 2019                    

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RETENTION AGREEMENT

This RETENTION AGREEMENT ("Agreement") is entered into by and between Arizona Public Service Company ("APS") and Maria Lacal ("Employee") (collectively the "Parties"). APS highly values and desires to continue to employ Employee, and Employee desires to continue to be employed by APS.

In consideration of the mutual agreements contained in this Agreement, the Parties agree effective December 19, 2008 ("Effective Date") as follows:

1.    Retention Bonus Payments.


1.1    Bonus. APS shall pay Employee a retention bonus of $100,000 ("Payment"), payable on January 1, 2012 ("Payment Date"), provided that Employee demonstrates sustained competent performance of her assigned job responsibilities, does not voluntarily terminate employment, and is not terminated for cause on or prior to Payment Date.

    The Payment shall not be included in Employee's compensation for pension purposes, nor is it deferrable under the Pinnacle West Company Corporation Deferred Compensation Plan. The Payment shall be subject to applicable withholdings including federal, state and local taxes.

1.2    Death or Disability. In the event of Employee's death or disability after the Effective Date, but prior to the Payment Date, so long as Employee was employed by APS through the date of death or disability, the Payment shall be paid in its entirety on the Payment Date.

1.3    Reimbursement. If Employee terminates employment, or is terminated by APS for cause, between the Payment Date and January 1, 2014, the Employee will repay APS the entire Payment, including any amounts paid by APS in connection with applicable tax withholding.

2.    Deferred Compensation Arrangement.

2.1    Plan. Beginning on or about December 17, 2008, APS shall establish a deferred compensation arrangement pursuant to the terms of this Section on behalf of the Employee ("Deferred Compensation Arrangement"). A bookkeeping entry ("Account") shall be utilized as a means for the measurement and determination of amounts, if any, to be paid to the Employee in accordance with the Deferred Compensation Arrangement.

2.2    Credits. APS shall credit an amount equal to Two Hundred Thousand Dollars ($200,000.00) to the Account effective on or about December 17, 2008, and an amount equal to Forty Thousand Dollars ($40,000.00) to the Account effective January 1, 2010 and each of the next four January 1 thereafter (each, a "Company Credit"), provided that the Employee remains employed with APS on each such crediting date and demonstrates sustained competent performance of her assigned job responsibilities.

2.3    Distribution. Subject to the applicable terms and conditions of this Agreement and provided the Employee remains actively employed with APS through the date she attains age 55, the Employee shall be entitled to a payment of benefits under the Deferred Compensation Arrangement in an amount equal to the Company Credits credited to her Account as of the date of her termination. By no later than December 31, 2008, the Employee must submit an election form as required by APS, to receive such distribution in the form of either a lump sum or an annuity. If



Employee is entitled to payment, it will begin, or in the case of a lump sum will be made, upon the Employee's termination of employment. If no timely election is made, payment shall be made in a lump sum. Any election made as to time and form of payment shall be irrevocable. Any payment made shall be subject to applicable withholdings including federal, state and local taxes.

2.4    Termination, Death or Disability.

(a) If Employee is terminated for cause, or Employee voluntarily terminates before she attains age 55, Employee shall forfeit all amounts credited to her Account and no benefits shall be payable under the Deferred Compensation Arrangement. If Employee's employment with APS is involuntarily terminated without cause by APS before she attains age 55, the Employee will be entitled to a lump sum payment in an amount equal to the Company Credits credited to her Account at the time of termination. Payment will be made at the time of the termination, or if applicable, at the time specified in Section 8 of this Agreement.

(b) In the event that the Employee is determined to be disabled under the Pinnacle West Capital Corporation Long-Term Disability Plan before the Employee terminates employment and such disability meets the definition of "disabled" for purposes of Section 409A of the Internal Revenue Code ("Code Section 409A"), (i) in the event the Employee has not yet attained age 55 on the date of such disability, the Account will not be credited with Company Credits, beginning as of the date of such disability, and the Employee shall be entitled to a lump sum payment at age 55 in an amount equal to the Company Credits credited to her Account at the time of distribution or (ii) in the event the Employee is age 55 or older on the date of such disability, the Employee shall be entitled to a lump sum payment in an amount equal to the Company Credits credited to her Account at the time of distribution, payable within 30 days after the date of disability.
(c) In the event that the Employee dies before she terminates employment or after the commencement of payments to him under the Deferred Compensation Arrangement, but before all such benefits have been paid in full, any balance credited to the Account that has not been paid under the Account as determined on the date of death shall be paid to the Employee's beneficiary in a lump sum within sixty (60) days after the date of death. The Employee's beneficiary for purposes of the Deferred Compensation Arrangement shall mean the person(s) or trust(s) specified by the Employee as the Employee's beneficiary, in the form and manner required by APS and on file with APS. In the event no beneficiary is named at the time of death, any benefits shall be paid to the Employee's estate.

3.     Confidentiality.
Employee shall hold the existence and terms of this Agreement in confidence. Employee shall not publicly or privately discuss or disclose the nature or content of this Agreement. However, Employee may disclose the terms of this Agreement if required by federal or state law, and Employee may disclose the terms of this Agreement to Employee's accountant, attorney, consultant and spouse. In addition, the Parties may disclose this Agreement as necessary to enforce its provisions.





                                /s/Maria Lacal                12/9/08        
                                Employee Signature            Date





FIRST AMENDMENT
TO THE
RETENTION AGREEMENT FOR MARIA LACAL

Arizona Public Service Company ("APS") previously entered into the Retention Agreement dated December 19, 2008 (the "Agreement") with Maria Lacal ("Employee"). By execution of this instrument, APS now desires to amend the Agreement as set forth below.
1.This First Amendment shall be effective as of the date on which it is executed.

2.This First Amendment amends the provisions of the Agreement noted below.

This First Amendment also supersedes the other provisions of the Agreement to the extent those provisions are inconsistent with the provisions and intent of this First Amendment.
3.Section 2.2 (Deferred Compensation Arrangement - Credits) of the Agreement is hereby amended and restated in its entirety to read as follows:
2.2 Credits. APS shall credit an amount equal to Two Hundred Thousand Dollars ($200,000) to the Account effective on or about December 17, 2008 and an amount equal to Forty Thousand Dollars ($40,000) to the Account effective January 1, 2010 (each, a "Company Credit"). APS shall allocate an additional Company Credit of Fifty Thousand Dollars ($50,000) to the Account effective January 1 of each of the next four years thereafter (commencing January 1, 2011), provided that the Employee remains employed with APS on each such crediting date and demonstrates sustained competent performance of her assigned job responsibilities.
4.The Agreement is hereby amended by the addition of the following new Section 9

(Compliant Operation and Interpretation with Code Section 409A) to the end thereof:

9. Compliant Operation and Interpretation with Code Section 409A. This Agreement is intended to comply with Code Section 409A and shall be administered in compliance with Section 409A or an exception thereto. Each provision of the Agreement shall be interpreted, to the extent possible, to comply with Code Section 409A or an exception thereto. Employee remains solely responsible for any adverse tax consequences imposed upon her by Section 409A.
5.Except as otherwise amended by this First Amendment, the Agreement shall continue in full force and effect.



IN WITNESS WHEREOF, APS and Employee have caused this First Amendment to be executed as of the date set forth below.
ARIZONA PUBLIC SERVICE COMPANY

By: /s/ George M. Kasper            
Date: 5/23/2011                
    

EMPLOYEE

/s/ Maria Lacal            

May 24, 2011            
Date





MEDICAL RETENTION AGREEMENT

This Medical Retention Agreement (the "Agreement") is entered into by and between Arizona Public Service Company ("APS") and Maria Lacal ("Employee").

1.Purpose. The purpose of this Agreement is to award a retention incentive that will be used to obtain medical insurance of the Employee's choice subject to the terms and conditions set forth below.

2.Retention Incentive.

(a)If Employee remains employed by APS through April 30, 2017, then APS shall be obligated to pay to Employee the amount of $260,000 (the "Retention Incentive").

(b)If Employee's employment with APS is involuntarily terminated by APS for Cause, the Retention Incentive will be forfeited. For purposes of this Agreement, the term "Cause" means any act or omission by Employee which could result in disciplinary action by APS against Employee in accordance with the personnel policies and procedures of APS. The determination of whether "Cause" exists shall be made by APS, in its sole and absolute discretion, in accordance with its personnel policies and procedures.

3.Payment of Retention Incentive. Employee's Retention Incentive will be paid to Employee in a single lump sum payment within 30 days following Employee's Separation from Service unless Employee is a Specified Employee on the date of her Separation from Service. If the Employee is a "Specified Employee" on the date of her Separation from Service, the Retention Incentive shall be paid in a single lump sum cash payment within 30 days following the first day of the seventh month following Employee's Separation from Service. For purposes of this Agreement, the term "Specified Employee" shall have the meaning ascribed to it in the Pinnacle West Capital Corporation Board of Director Minutes dated October 17, 2007.

4.Continued Health Benefit. Effective upon Employee's Separation from Service for reasons other than Cause, Employee and APS will enter into a "Settlement Agreement" pursuant to Section 3.2(d) of the Pinnacle West Capital Corporation Group Medical Plan (the "Group Medical Plan"). The Settlement Agreement shall entitle Employee to purchase continued health insurance coverage (the "Continuation Coverage") under the Group Medical Plan on the following terms and conditions:

(a)The Continuation Coverage may be continued for Employee and Employee's "Eligible Dependents," determined as of the day of Employee's Separation from Service and in accordance with the definition of "Eligible Dependents" set forth in the Group Medical Plan. The Continuation Coverage for Employee or Employee's spouse shall end on the date on which Employee or Employee's spouse, as the case may be, becomes eligible to elect to receive Medicare coverage. The Continuation Coverage for any Eligible Dependent other than Employee's spouse shall end on the date as of which the dependent is no longer an "Eligible Dependent" as determined in accordance with the Group Medical Plan.





(b)    In order to receive the Continuation Coverage, Employee (or Employee's Eligible Dependents following Employee's death) must pay the full premium (Employer and participant portions) for the Continuation Coverage.

(c)    In order to receive the Continuation Coverage, Employee must elect it on or before the last day of her employment. If Employee does not elect to receive the Continuation Coverage on or before the last day of her employment, she will no longer be eligible to receive it at any time in the future. If Employee elects Continuation Coverage and later chooses to discontinue her participation or the participation by any of her dependents, neither Employee nor her dependents shall be eligible for Continuation Coverage at any time in the future.

(d)    The Continuation Coverage will be subject to the prov1s10ns of Article Four of the Medical Plan, which provides the rules for coordination of benefits. The provisions of this paragraph supersede any contrary provisions in Article Four of the Group Medical Plan as it applies to Employee and Employee's Eligible Dependents.

(e)    Employee and Employee's Eligible Dependents shall not be entitled to any benefits other than those provided from time to time under the Group Medical Plan to "Pre-age 65 Retirees" and their eligible dependents. For this purpose, a "Pre-age 65 Retiree" is a retired former employee of APS who is not yet eligible for Medicare coverage and who is then covered by the Group Medical Plan. The Continuation Coverage of Employee and Employee's Eligible Dependents under the Group Medical Plan will be subject to all of the terms and provisions of the Group Medical Plan, as it may be amended from time to time.

(f)    Pursuant to the Patient Protection and Affordable Care Act and the Health Care & Education Affordability Reconciliation Act (collectively, the "Health Care Reform Act"), penalties may be imposed upon an employer that provides discriminatory health care benefits. If APS concludes, in the exercise of its discretion and based upon the advice of legal or other counsel, that the Continuation Coverage provided to Employee pursuant to this Section will subject APS to any fines, taxes, or penalties pursuant to the Health Care Reform Act or any other applicable state or federal law, rules or regulations, APS reserves the right to immediately discontinue the Continuation Coverage and the payment or provision of any benefits that result in the imposition of such fines, taxes, or penalties. In such event, APS shall have no obligation to replace the benefit or compensate Employee for lost coverage.

(g)    Employee acknowledges that APS has reserved the right to amend or terminate the Group Medical Plan both before and after Employee's Separation from Service. Any such amendments will apply to Employee and Employee's Eligible Dependents and the Continuation Coverage to which Employee and Employee's Eligible Dependents are entitled. If APS amends or terminates the Group Medical Plan or the retiree medical coverage provided pursuant to the Group Medical Plan, the Continuation Coverage available to Employee and Employee's Eligible Dependents will be amended or terminated as well.
2




(h)    Any reference in this Agreement to any particular provision of the Group Medical Plan will be deemed to also refer to the corresponding provision of any amended, restated or any replacement plan.

5.    Confidentiality. Employee shall hold the existence and terms of this Agreement in confidence. Employee shall not publicly or privately discuss or disclose the nature or content of this Agreement. However, Employee may disclose the terms of this Agreement if required by federal or state law, and Employee may disclose the terms of this Agreement to Employee's accountant, attorney, consultant and spouse. In addition, APS and Employee may disclose this Agreement as necessary to enforce its provisions.

6.    Reporting to Federal and State Agencies. Nothing in this Agreement shall be construed to prohibit Employee from reporting or disclosing any suspected instance of illegal activity of any nature, any nuclear safety concerns, any workplace safety concerns, or any public safety concerns to the Nuclear Regulatory Commission ("NRC"), the United States Department of Labor ("DOL"), or any other federal, state, or local government agency or court. This Agreement shall not be construed to prohibit Employee from providing information to the NRC, DOL, Equal Employment Opportunity Commission, United States Securities and Exchange Commission, Occupational Safety and Health Administration, or Arizona Division of Occupational Safety and Health, or testifying in any civil or criminal proceedings, even if such information or testimony being provided relates to the claims or matters covered by this Agreement. This Agreement shall not be construed as a waiver or withdrawal of any safety concerns which Employee has or may have reported to the NRC or DOL, or withdrawal of any participation by Employee in any NRC proceedings. In this regard, the parties to this Agreement understand that this Agreement shall be interpreted in a manner consistent with 10 CFR § 50.7(f). Notwithstanding anything to the contrary in this paragraph, Employee hereby waives and releases any right to receive any relief as a result of the Employee's participation in any investigation or proceeding of the NRC, DOL, or any federal, state, or local government agency or court.

7.    Law. The prov1s1ons of this Agreement shall be construed and interpreted according to the laws of the State of Arizona to the extent not preempted by Federal law.

8.    Severability. If any provision of this Agreement is held to be invalid, the remaining provisions shall remain in full force and effect.

9.    Entire Agreement. APS and Employee acknowledge and agree that this Agreement constitute the entire agreement between APS and Employee with respect to the subject matter hereof.

10.    Amendments. This Agreement may not be modified, altered or changed except by a written agreement signed by APS and Employee.

11.    Withholding. The Retention Incentive, if any, is subject to reduction in order to comply with applicable federal, state and local tax withholding requirements and shall be reflected on Employee's Form W-2 for the year in which it is paid.

3




12.    Section 409A Compliance. Certain payments and benefits provided by this Agreement may be subject to the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the "Code").

(a)    Separation from Service. Notwithstanding anything in this Agreement to the contrary, no payment shall be made pursuant to Section 2 prior to Employee's Separation from Service. For purposes of this Agreement, the term "Separation from Service" shall have the meaning ascribed to it in Treasury Regulation Section 1.409A l(h).

(b)    No Elections; No Acceleration. Employee may not elect to receive cash or any other allowance in lieu of any benefits provided by this Agreement. Employee does not have any right to make any election regarding the time or form of any payment due under this Agreement. Under no circumstances may the time or schedule of any payment made or benefit provided pursuant to this Agreement be accelerated or subject to a further deferral except as otherwise permitted or required pursuant to the regulations and other guidance issued pursuant to Section 409A.

(c)    Compliant Operation. This Agreement shall be operated in compliance with Section 409A or an exception thereto and each provision of this Agreement shall be interpreted, to the extent possible, to comply with Section 409A or qualify for an exception thereto. Nevertheless, APS cannot, and does not, guarantee any particular tax effect or treatment of the amounts due under this Agreement. Except for APS' responsibility to withhold applicable income and employment taxes from compensation paid or provided to Employee, APS will not be responsible for the payment of any applicable taxes on compensation paid or provided to Employee.

4




IN WITNESS WHEREOF, APS and Employee have executed this Agreement on the dates set forth below.

ARIZONA PUBLIC SERVICE COMPANY


By : /s/ Donald E. Brandt        
Donald E. Brandt
Chairman and Chief Executive Officer

Date: September 15, 2014                

EMPLOYEE

/s/ Maria Lacal                        

Date: October 31, 2014                    
5


Discretionary Credit Award Agreement
This Discretionary Credit Award Agreement (the “Agreement”) is entered into by and between Arizona Public Service Company (“APS”) and Maria Lacal (“Employee”).
1.Background. The Company and Employee previously entered into a Retention Agreement dated December 19, 2008 and amended as of May 24, 2011 (the “2008 Agreement”), which continues to remain in effect.
2.Purpose. Section 3.9 of the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Deferred Compensation Plan”) allows APS to award Discretionary Credits in such amounts and subject to such terms and conditions as APS deems appropriate. The purpose of this Agreement is to award Discretionary Credits to Employee subject to the terms and conditions set forth below.
3.Definitions. A number of key terms, with specialized meanings, are used throughout this Agreement. These key terms are identified by the capitalization of the initial letter of each word or phrase even when the word or phrase does not begin a sentence. Each of these key terms will be given the meaning ascribed to it in the Deferred Compensation Plan unless the term is defined in this Agreement. Whenever these key terms are used, they will be given the defined meaning unless a clearly different meaning is required by the context.
4.Discretionary Credits. Two Discretionary Credits in the aggregate amount of $100,000 will be allocated to a Discretionary Credit Account (the “Discretionary Credit Account”) established for the benefit of Employee pursuant to Section 3.9 of the Deferred Compensation Plan. APS shall credit the Discretionary Credit Account with an amount equal to $50,000 on January 1, 2015 and an amount equal to $50,000 on January 1, 2016 provided that the Employee remains employed with APS on each such crediting date and demonstrates sustained competent performance of her assigned job responsibilities.
5.Interest. The Discretionary Credit Account shall be credited with interest in accordance with Section 3.5 of the Deferred Compensation Plan.
6.Modification of 2008 Agreement. Effective retroactive to January 1, 2014, the “Company Credits” credited to Employee pursuant to the 2008 Agreement shall be credited with interest calculated in accordance with Section 3.5 of the Deferred Compensation Plan. All other terms and conditions of the 2008 Agreement shall continue in full force and effect.
7.Vesting. The Discretionary Credit Account vests on April 30, 2017. If Employee Separates from Service prior to April 30, 2017, the amounts allocated to the Discretionary Credit Account will be forfeited; provided, however, that if Employee’s employment with APS is involuntarily terminated by APS without Cause, Employee dies or Employee becomes Disabled prior to April 30, 2017, all amounts previously credited to the Discretionary Credit Account will be fully vested as of the date of the termination by APS without Cause, death or Disability as applicable. For purposes of this document, “Disability” shall have the meaning ascribed to it in the Pinnacle West Capital Corporation Long-Term Disability Plan. For purposes of this



document, “Cause” means any act or omission that could result in disciplinary action pursuant to applicable laws or APS policies and procedures, as determined in the sole discretion of APS. The determination of whether “Cause” exists shall be made by APS, in its sole and absolute discretion, in accordance with its personnel policies and procedures.
8.Payment of Discretionary Credits.
(a)General Rule. Except as otherwise provided below in this Section 8, Employee’s vested interest in her Discretionary Credit Account will be paid to Employee in substantially equal installments over a period of approximately five years following Employee’s Separation from Service with the first installment payment to made within 30 days following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation from Service, the first installment payment shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date. The Discretionary Credit Account may not be distributed as a ShortTerm Payout or due to an Unforeseeable Financial Emergency.
(b)Disability. If Employee becomes Disabled prior to her Separation from Service and if such Disability occurs prior to April 30, 2017, Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account on the first business day following April 30, 2017 as long as the Disability constitutes a “disability” as defined in Section 409A of the Code. If the Disability does not constitute a “disability” as defined in Section 409A of the Code, the general rule set forth in Section 8(a) will apply, unless Employee incurs a Separation from Service before April 30, 2017, in which case Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation from Service, Employee’s vested interest in her Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
(c)Death. If Employee dies while employed by the Company, or after the commencement of installment payments as described in Section 8(a) but before all such payments have been made in full, the Beneficiary designated by Employee pursuant to the Deferred Compensation Plan shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within sixty days of Employee’s death.
(d)Termination without Cause. If Employee’s employment is terminated by the Company without cause and if, as a result of such termination, Employee incurs a Separation from Service before April 30, 2017, Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation
    2    


from Service, Employee’s vested interest in her Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
9.Employee’s Plan Status. Regardless of whether Employee makes an Annual Deferral pursuant to the terms of the Deferred Compensation Plan for the relevant Plan Year, Employee shall be deemed to be a Participant in the Deferred Compensation Plan and to have elected to participate in the Deferred Compensation Plan for the limited purpose of receiving the Discretionary Credits described in this Agreement. This Agreement shall be deemed to be Employee’s Election Form for purposes of Section 2.2 and Section 3.3 of the Deferred Compensation Plan.
10.Relationship to Other Benefits. The Discretionary Credits allocated to Employee pursuant to this Agreement shall not be taken into account as compensation or for purposes of determining any benefits due to Employee pursuant to the terms of any pension, retirement, savings, profit sharing, incentive, group insurance or other tax qualified or nonqualified benefit plan sponsored by APS, Pinnacle West Capital Corporation or any affiliate of either. In addition, the amounts payable to Employee attributable to the Discretionary Credit Account established for Employee pursuant to the Deferred Compensation Plan shall be disregarded for purposes of the benefit plans referred to in the preceding sentence.
11.Plan Document. As provided above, this Agreement is entered into pursuant to the provisions of Section 3.9 of the Deferred Compensation Plan. Accordingly, except as otherwise set forth in this Agreement, the provisions of the Deferred Compensation Plan shall apply in determining the rights of Employee as well as the administration of Employee’s Discretionary Credit Account. In cases of conflict, this Agreement controls over any conflicting provisions of the Deferred Compensation Plan, except as may be required by Section 409A of the Internal Revenue Code or the provisions of any other applicable law or regulation.
12.Amendments. This Agreement may not be modified, altered or changed except by a written agreement signed by APS and Employee.
13.Confidentiality. Employee shall hold the existence and terms of this Agreement in confidence. Employee shall not publicly or privately discuss or disclose the nature or content of this Agreement. However, Employee may disclose the terms of this Agreement if required by federal or state law, and Employee may disclose the terms of this Agreement to Employee’s accountant, attorney, consultant and spouse. In addition, APS and Employee may disclose this Agreement as necessary to enforce its provisions.
14.Reporting to Federal and State Agencies. Nothing in this Agreement shall be construed to prohibit Employee from reporting or disclosing any suspected instance of illegal activity of any nature, any nuclear safety concerns, any workplace safety concerns, or any public safety concerns to the Nuclear Regulatory Commission (“NRC”), the United States Department of Labor (“DOL”), or any other federal, state, or local government agency or court. This Agreement shall not be construed to prohibit Employee from providing information to the NRC, DOL, Equal Employment Opportunity Commission, United States Securities and Exchange
    3    


Commission, Occupational Safety and Health Administration, or Arizona Division of Occupational Safety and Health, or testifying in any civil or criminal proceedings, even if such information or testimony being provided relates to the claims or matters covered by this Agreement. This Agreement shall not be construed as a waiver or withdrawal of any safety concerns which Employee has or may have reported to the NRC or DOL, or withdrawal of any participation by Employee in any NRC proceedings. In this regard, the parties to this Agreement understand that this Agreement shall be interpreted in a manner consistent with 10 CFR § 50.7(f). Notwithstanding anything to the contrary in this paragraph, Employee hereby waives and releases any right to receive any relief as a result of the Employee's participation in any investigation or proceeding of the NRC, DOL, or any federal, state, or local government agency or court.
15.Entire Agreement. APS and Employee acknowledge and agree that this Agreement and the Deferred Compensation Plan constitute the entire agreement between APS and Employee with respect to the subject matter hereof.
16.Severability. If any provision of this Agreement is held to be invalid, the remaining provisions shall remain in full force and effect.
IN WITNESS WHEREOF, APS and Employee have executed this Agreement on the dates set forth below.
ARIZONA PUBLIC SERVICE COMPANY



By:/s/ Donald E. Brandt                
Donald E. Brandt
Chairman and Chief Executive Officer

Date:    September 15, 2014                


EMPLOYEE


/s/ Maria Lacal                    
Maria Lacal

Date:    October 31, 2014                

    4    

Discretionary Credit Award Agreement
This Discretionary Credit Award Agreement (the “Agreement”) is entered into by and between Arizona Public Service Company (“APS”) and Maria Lacal (“Employee”).
1.Background. The Company and Employee previously entered into a Retention Agreement dated December 19, 2008 and amended as of May 24, 2011 and a Discretionary Credit Award Agreement dated October 31, 2014, which continue to remain in effect.
2.Purpose. Section 3.9 of the Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates (the “Deferred Compensation Plan”) allows APS to award Discretionary Credits in such amounts and subject to such terms and conditions as APS deems appropriate. The purpose of this Agreement is to award Discretionary Credits to Employee subject to the terms and conditions set forth below.
3.Definitions. A number of key terms, with specialized meanings, are used throughout this Agreement. These key terms are identified by the capitalization of the initial letter of each word or phrase even when the word or phrase does not begin a sentence. Each of these key terms will be given the meaning ascribed to it in the Deferred Compensation Plan unless the term is defined in this Agreement. Whenever these key terms are used, they will be given the defined meaning unless a clearly different meaning is required by the context.
4.Discretionary Credits. Two Discretionary Credits in the aggregate amount of $250,000 will be allocated to a Discretionary Credit Account (the “Discretionary Credit Account”) established for the benefit of Employee pursuant to Section 3.9 of the Deferred Compensation Plan. APS shall credit the Discretionary Credit Account with an amount equal to $125,000 on July 1, 2017 and an amount equal to $125,000 on July 1, 2018 provided that the Employee remains employed with APS on each such crediting date and demonstrates sustained competent performance of her assigned job responsibilities.
5.Interest. The Discretionary Credit Account shall be credited with interest in accordance with Section 3.5 of the Deferred Compensation Plan.
6.Vesting. The Discretionary Credit Account vests on July 1, 2019. If Employee Separates from Service prior to July 1, 2019, the amounts allocated to the Discretionary Credit Account will be forfeited; provided, however, that if Employee’s employment with APS is involuntarily terminated by APS without Cause, Employee dies or Employee becomes Disabled prior to July 1, 2019, all amounts previously credited to the Discretionary Credit Account will be fully vested as of the date of the termination by APS without Cause, death or Disability as applicable. For purposes of this document, “Disability” shall have the meaning ascribed to it in the Pinnacle West Capital Corporation Long-Term Disability Plan. For purposes of this document, “Cause” means any act or omission that could result in disciplinary action pursuant to applicable laws or APS policies and procedures, as determined in the sole discretion of APS. The determination of whether “Cause” exists shall be made by APS, in its sole and absolute discretion, in accordance with its personnel policies and procedures.




7.Payment of Discretionary Credits.
(a)General Rule. Except as otherwise provided below in this Section 7, Employee’s vested interest in her Discretionary Credit Account will be paid to Employee in substantially equal installments over a period of approximately five years following Employee’s Separation from Service with the first installment payment to made within 30 days following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation from Service, the first installment payment shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service and each subsequent installment payment shall be made on the next four anniversaries of the first payment date. The Discretionary Credit Account may not be distributed as a ShortTerm Payout or due to an Unforeseeable Financial Emergency.
(b)Disability. If Employee becomes Disabled prior to her Separation from Service and if such Disability occurs prior to July 1, 2019, Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account on the first business day following July 1, 2019 as long as the Disability constitutes a “disability” as defined in Section 409A of the Code. If the Disability does not constitute a “disability” as defined in Section 409A of the Code, the general rule set forth in Section 7(a) will apply, unless Employee incurs a Separation from Service before July 1, 2019, in which case Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation from Service, Employee’s vested interest in her Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
(c)Death. If Employee dies while employed by the Company, or after the commencement of installment payments as described in Section 7(a) but before all such payments have been made in full, the Beneficiary designated by Employee pursuant to the Deferred Compensation Plan shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within sixty days of Employee’s death.
(d)Termination without Cause. If Employee’s employment is terminated by the Company without cause and if, as a result of such termination, Employee incurs a Separation from Service before July 1, 2019, Employee shall receive a single lump sum payment of Employee’s vested interest in her Discretionary Credit Account within 30 days following Employee’s Separation from Service, unless Employee is a Specified Employee on the date of her Separation from Service. If Employee is a Specified Employee on the date of her Separation from Service, Employee’s vested interest in her Discretionary Credit Account shall be paid within 30 days following the first day of the seventh month following Employee’s Separation from Service.
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8.Employee’s Plan Status. Regardless of whether Employee makes an Annual Deferral pursuant to the terms of the Deferred Compensation Plan for the relevant Plan Year, Employee shall be deemed to be a Participant in the Deferred Compensation Plan and to have elected to participate in the Deferred Compensation Plan for the limited purpose of receiving the Discretionary Credits described in this Agreement. This Agreement shall be deemed to be Employee’s Election Form for purposes of Section 2.2 and Section 3.3 of the Deferred Compensation Plan.
9.Relationship to Other Benefits. The Discretionary Credits allocated to Employee pursuant to this Agreement shall not be taken into account as compensation or for purposes of determining any benefits due to Employee pursuant to the terms of any pension, retirement, savings, profit sharing, incentive, group insurance or other tax qualified or nonqualified benefit plan sponsored by APS, Pinnacle West Capital Corporation or any affiliate of either. In addition, the amounts payable to Employee attributable to the Discretionary Credit Account established for Employee pursuant to the Deferred Compensation Plan shall be disregarded for purposes of the benefit plans referred to in the preceding sentence.
10.Plan Document. As provided above, this Agreement is entered into pursuant to the provisions of Section 3.9 of the Deferred Compensation Plan. Accordingly, except as otherwise set forth in this Agreement, the provisions of the Deferred Compensation Plan shall apply in determining the rights of Employee as well as the administration of Employee’s Discretionary Credit Account. In cases of conflict, this Agreement controls over any conflicting provisions of the Deferred Compensation Plan, except as may be required by Section 409A of the Internal Revenue Code or the provisions of any other applicable law or regulation.
11.Amendments. This Agreement may not be modified, altered or changed except by a written agreement signed by APS and Employee.
12.Confidentiality. Employee shall hold the existence and terms of this Agreement in confidence. Employee shall not publicly or privately discuss or disclose the nature or content of this Agreement. However, Employee may disclose the terms of this Agreement if required by federal or state law, and Employee may disclose the terms of this Agreement to Employee’s accountant, attorney, consultant and spouse. In addition, APS and Employee may disclose this Agreement as necessary to enforce its provisions.
13.Reporting to Federal and State Agencies. Nothing in this Agreement shall be construed to prohibit Employee from reporting or disclosing any suspected instance of illegal activity of any nature, any nuclear safety concerns, any workplace safety concerns, or any public safety concerns to the Nuclear Regulatory Commission (“NRC”), the United States Department of Labor (“DOL”), or any other federal, state, or local government agency or court. This Agreement shall not be construed to prohibit Employee from providing information to the NRC, DOL, Equal Employment Opportunity Commission, United States Securities and Exchange Commission, Occupational Safety and Health Administration, or Arizona Division of Occupational Safety and Health, or testifying in any civil or criminal proceedings, even if such information or testimony being provided relates to the claims or matters covered by this Agreement. This Agreement shall not be construed as a waiver or withdrawal of any safety
    3    


concerns which Employee has or may have reported to the NRC or DOL, or withdrawal of any participation by Employee in any NRC proceedings. In this regard, the parties to this Agreement understand that this Agreement shall be interpreted in a manner consistent with 10 CFR § 50.7(f). Notwithstanding anything to the contrary in this paragraph, Employee hereby waives and releases any right to receive any relief as a result of the Employee's participation in any investigation or proceeding of the NRC, DOL, or any federal, state, or local government agency or court.
14.Entire Agreement. APS and Employee acknowledge and agree that this Agreement and the Deferred Compensation Plan constitute the entire agreement between APS and Employee with respect to the subject matter hereof.
15.Severability. If any provision of this Agreement is held to be invalid, the remaining provisions shall remain in full force and effect.
IN WITNESS WHEREOF, APS and Employee have executed this Agreement on the dates set forth below.
ARIZONA PUBLIC SERVICE COMPANY



By: /s/ Donald E. Brandt                
Donald E. Brandt
Chairman and Chief Executive Officer

Date:    June 27, 2016                    


EMPLOYEE


/s/ Maria Lacal                    
Maria Lacal

Date:    September 29, 2016                

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Exhibit 10.6.4
Summary of 2021 Incentive Plans

On December 15, 2020, the Human Resources Committee (the “Committee”) of the Pinnacle West Capital Corporation (“Pinnacle West”) Board of Directors (the “Board”) approved the portion of the Arizona Public Service Company ("APS") 2021 Annual Incentive Award Plan (the “APS Plan”) that provides an incentive award opportunity for Jeffrey B. Guldner, Chairman of the Board, President and Chief Executive Officer of Pinnacle West and Chairman of the Board and Chief Executive Officer of APS. On December 16, 2020, the Board, acting on the recommendation of the Committee, approved the portion of the APS Plan that includes an incentive award opportunity for James R. Hatfield, Executive Vice President and Chief Administrative Officer of Pinnacle West and APS, Daniel T. Froetscher, President and Chief Operating Office of APS, Theodore N. Geisler, Senior Vice President and Chief Financial Officer of Pinnacle West and APS and Robert E. Smith, Senior Vice President and General Counsel of Pinnacle West and APS.

No incentive payments will be awarded under the APS Plan unless Pinnacle West, with respect to Mr. Guldner, or APS, with respect to Messrs. Hatfield, Froetscher, Geisler and Smith, each achieves a specified threshold earnings level. The award opportunities for Mr. Guldner under the APS Plan are based on the achievement of specified 2021 Pinnacle West earnings levels and specified business unit performance goals. Mr. Guldner has a target award opportunity of up to 110% of his base salary. Mr. Guldner may earn less or more than the target amount, up to a maximum award opportunity of 220% of base salary, depending on the achievement of the earnings and business unit performance goals separately or in combination, and before adjustment for individual performance. The business unit performance indicators for Mr. Guldner are in the functional areas of customer service, corporate resources, fossil generation, transmission and distribution, and performance of the Palo Verde Generating Station.

The award opportunities for Messrs. Hatfield, Froetscher, Geisler and Smith under the APS Plan are based on the achievement of specified 2021 APS earnings levels and specified business unit performance goals. Mr. Hatfield has a target award opportunity of up to 75% of his base salary, Mr. Froetscher has a target award opportunity of up to 90% of his base salary, Mr. Geisler has a target award opportunity of up to 70% of his base salary, and Mr. Smith has a target award opportunity of up to 65% of his base salary. Messrs. Hatfield, Froetscher, Geisler and Smith may earn less or more than the target amount, up to a maximum award opportunity of 150% of base salary for Mr. Hatfield, 180% for Mr. Froetscher, 140% for Mr. Geisler, and 130% for Mr. Smith, depending on the achievement of the earnings and business unit performance goals separately or in combination, and before adjustment for individual performance. The business unit performance indicators that will be considered for Messrs. Hatfield, Froetscher, Geisler and Smith are derived from the APS areas of focus of culture, reliability, customer centric and affordability, as provided in its APS Promise.

The Committee may adjust targets or incentive results under the APS Plan to reflect unanticipated events or unusual or nonrecurring adjustments to Pinnacle West or APS earnings (as applicable) that arise in the APS Plan year, including without limitation, Arizona Corporation Commission rate-related impacts on earnings. Any awards for Messrs. Guldner, Hatfield, Froetscher, Geisler and Smith are subject to potential forfeiture or recovery in accordance with Pinnacle West’s Clawback Policy.





PERFORMANCE SHARE AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of __________ (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and _________________ (“Employee”).
BACKGROUND
A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Share Awards and Dividend Equivalent Awards may be granted to employees of the Company and its subsidiaries.
B.The Company desires to grant to Employee Performance Shares and Dividend Equivalents under the terms of the Plan.
C.Pursuant to the Plan, the Company and Employee agree as follows:
AGREEMENT
a.Grant of Award. Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee ____________ (____) Performance Shares and related Dividend Equivalents. The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”
b.Award Subject to Plan. This Performance Share Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.
c.Performance Period. The Performance Period for this Award begins January 1, _____, and ends December 31, ______.
d.Payment and Vesting.
(i)Performance Shares Payable In Stock. As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Total Shareholder Return (as defined herein) as compared to the Total Shareholder Return of the companies in the Edison Electric Institute Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein). The Company then will deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below. The Company anticipates that the Stock payout, if any, related to the Company’s Total Shareholder Return will be made by ________. The Company anticipates that the Stock payout, if any, related to the Performance Metrics will be made by ________ and in no event will such Stock payout be made later than ________.
(ii)Normal or Early Retirement, Death or Disability; Late Career Recipient.
(i) Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient (as defined below), in the case of Employee’s death or Disability, Employee shall be deemed to have been employed by the Company through the end of the Performance
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Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(ii) In the case of Employee’s Termination of Employment during the Performance Period which constitutes an Early Retirement or a Normal Retirement under the Retirement Plan, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(iii) If, at the time of Employee’s death, Disability or retirement Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient”. Upon a Late Career Recipient’s retirement during the Performance Period, Employee will receive a straight prorated payout of the number of Performance Shares calculated in accordance with Section 5 based on the number of days Employee was employed during the Performance Period. Upon a Late Career Recipient’s retirement following the end of the Performance Period, Employee will receive a payout of the number of Performance Shares calculated in accordance with Section 5. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock. Employee will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(iii)Termination Without Cause. In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer (“CEO”) of the Company may determine in his discretion if, to what extent, and when any unvested portion of the Performance Shares granted under this Agreement should vest; provided, however, that (i) any vesting of unvested Performance Shares granted under this Agreement pursuant to this Section 4(c) shall be approved by the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Performance Shares to vest.
(iv)Termination For Cause. Notwithstanding any other provision in this Section 4, in the event Employee is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination. For purposes only of this Section 4(d), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its subsidiaries or negatively affects any of the Company’s or any of its subsidiaries employees or customers.
(v)Disability. “Disability” has the meaning set forth for such term in the Retirement Plan.
(vi)Dividend Equivalents. In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to this Section 4, the Company also will deliver to Employee fully transferrable shares of Stock equal in value to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Performance Shares relate from the Date of Grant to the date of the Stock payout, plus interest on such amount at the rate of 5 percent compounded quarterly, as determined pursuant to the Plan. The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable date of the Stock payout. No fractional Stock
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shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.
(vii)Impact on Retirement Plans. The value of the shares of Stock distributed upon payment for the Performance Shares and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.
e.Performance Criteria and Adjustments. Fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(a) and fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(b). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Award Agreement greater than 2.0 times the Base Grant.
(i)Adjustment of Base Grant for Total Shareholder Return. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Total Shareholder Return” as compared to the Total Shareholder Return of the companies in the Growth Index during the Performance Period, as follows:
If the Company’s Total Shareholder Return Over The Performance Period As Compared to the Total Shareholder Return of the Companies in the Growth Index is:

The Number of Performance Shares will be:
90th Percentile or greater
75th Percentile
1.0 X Base Grant
.75 X Base Grant
55th Percentile 0.5 X Base Grant
25th Percentile 0.25 X Base Grant
Less than 25th Percentile None
If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than 1.0 times the Base Grant.
(ii)Adjustment of Base Grant for Performance Metrics. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:
If the Company’s Average Performance is:
The Number of Performance Shares will be:

90th Percentile or greater
75th Percentile
1.0 X Base Grant
.75 X Base Grant
55th Percentile 0.5 X Base Grant
25th Percentile 0.25 X Base Grant
Less than 25th Percentile None
If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than 1.0 times the Base Grant.
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f.Definitions.
(i)Performance Metrics. The “Performance Metrics” for the Performance Period are: (i) the System Average Interruption Frequency Index (Major Events Excluded) (“SAIFI”); (ii) Arizona Public Service Company’s customer to employee improvement ratio; (iii) the OSHA rate (All Incident Injury Rate); (iv) nuclear capacity factor; and (v) the J.D. Power Electric Utility Residential Study Overall Customer Satisfaction Index.
(1)With respect to the Performance Metric described in clause (i) of this Subsection 6(a), the Edison Electric Institute (“EEI”) will provide data on an annual basis regarding the SAIFI result of the participating companies; the Company will calculate its SAIFI result for the year in question and determine its percentile ranking based on the information provided by EEI.
(2)With respect to the Performance Metric described in clause (ii) of this Subsection 6(a), S&P Global Market Intelligence (“Market Intelligence”), an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those companies whose customers and employees were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.
(3)With respect to the Performance Metric described in clause (iii) of this Subsection 6(a), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.
(4)With respect to the Performance Metric described in clause (iv) of this Subsection 6(a), Market Intelligence will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those plants that were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.
(5)With respect to the Performance Metric described in clause (v) of this Subsection 6(a), the J.D. Power Electric Utility Residential Study will provide data on an annual basis regarding the scores of the participating companies; the Company will calculate its percentile ranking within the large, investor-owned utility peer set based on the information provided by J.D. Power.
(6)The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the Performance Period (each, an “Average Performance Metric”); provided, however, that if the third year of a Performance Metric is not calculable by December 15 of the following year, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable. The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics. If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile. For example, if the Performance Metric was in the top quartile for two Performance Periods and in the lowest quartile in the other
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Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1) and the Average Performance Metric would be the 75th percentile (3 /4). The calculations in this Subsection 6(a)(6) will be verified by the Company’s internal auditors.
(7)If either EEI or Market Intelligence discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or Market Intelligence, as the case may be. If the J.D. Power Electric Utility Residential Customer Satisfaction Study (or a successor JD Power survey) is not available during each of the years of the Performance Period, the Performance Metric associated with the JD Power Residential Survey (Subsection 6(a)(5)) will be disregarded and not included in the Company’s Average Performance for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b).
(ii)Total Shareholder Return. “Total Shareholder Return” for the Performance Period is the measure of a company’s stock price appreciation plus any dividends paid during the Performance Period. Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered. Total Shareholder Return for the Company and the companies in the Growth Index will be determined using the Daily Comparative Return as calculated by Bloomberg (or other independent third party data system). If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison. In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use. Once the Total Shareholder Returns of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least. Percentiles will be calculated (interpolated from 0% to 100%) based on a company’s relative ranking. Percentiles will be carried out to one (1) decimal place. If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking. These calculations will be verified by the Company’s internal auditors.
g.Termination of Award. This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer employed by the Company or any of its subsidiaries, whether due to voluntary or involuntary termination, death, retirement, Disability, or otherwise, except as specifically set forth in Section 4 above or in Article 15 of the Plan. Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.
h.Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement.
i.Tax Withholding. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout of Stock hereunder by having the Company withhold shares of Stock from such payout.
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j.Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its subsidiaries.
k.Confidentiality. During Employee’s employment and after termination thereof, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.
Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership. For purposes of this Section 11, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.
l.Restrictive Covenants.
(i)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity. 
(ii)Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s Termination of Employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.
(iii)Remedies. If Employee fails to comply with Sections 11, 12(a), or 12(b) in a material respect, the Company may (i) cause any of Employee’s unvested Performance Shares and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Performance Shares or Dividend Equivalents, and/or (iii) pursue any other
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rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.
m.Cooperation with Government Agencies. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically permitted by law, because Employee is providing information to government investigatory or enforcement agencies, such as the Nuclear Regulatory Commission, Department of Labor, Equal Employment Opportunity Commission (or its state equivalent), National Labor Relations Board, the Occupational Safety and Health Administration (or its state equivalent) or the Securities and Exchange Commission. This Award Agreement also does not limit Employee’s ability to communicate with any government agency regarding matters within the agency’s jurisdiction or otherwise participate in any investigation or proceedings that may be conducted by such agency, including providing documents or other information without notice to the Company. Nothing in this Award Agreement shall prevent Employee from the disclosure of Confidential Information or trade secrets that: (i) is made: (a) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (b) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is permitted to be made, and is made, under seal. In the event that Employee files a lawsuit alleging retaliation by Company for reporting a suspected violation of law, Employee may disclose Confidential Information or trade secrets related to the suspected violation of law or alleged retaliation to Employee’s attorney and use the Confidential Information or trade secrets in the court proceeding if Employee or Employee’s attorney: (i) files any document containing Confidential Information or trade secrets, under seal if permitted; and (ii) does not disclose the Confidential Information or trade secrets, except pursuant to or in accordance with a court order. The Company provides this notice in compliance with federal law, including the Defend Trade Secrets Act of 2016.
n.Clawback. The portion of this Award, if any, that is earned based on the Company’s Total Shareholder Return will be subject to potential forfeiture or recovery to the extent called for by the Company’s Clawback Policy. The Clawback Policy may include such provisions as the Human Resources Committee of the Board of Directors determines to be necessary or appropriate either to comply with any applicable law or listing standard or in light of Company ethics or other policies and practices. Specific requirements of the Clawback Policy may be adopted and amended at such times as the Human Resources Committee of the Board of Directors determines in its discretion. By accepting this Award, Employee consents and agrees to abide by such Clawback Policy.
o.Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.
p.Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan prospectus.
q.Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify for favorable tax treatment either for the Company or Employee or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.
r.Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together will constitute one and the same instrument. Counterpart signature pages
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to this Agreement transmitted by facsimile transmission, by electronic mail in portable document format (.pdf), or by any other electronic means will have the same effect as physical delivery of the paper document bearing an original signature.
IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.
PINNACLE WEST CAPITAL CORPORATION
By: ________________________________

Its: _______________________________
                        Date: ________________________________


EMPLOYEE
By:                        

Date: ___________________________________
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PERFORMANCE SHARE AWARD AGREEMENT

THIS AWARD AGREEMENT is made and entered into as of ____________ (the “Date of Grant”), by and between Pinnacle West Capital Corporation (the “Company”), and _________________ (“Employee”).
BACKGROUND
A.The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Share Awards and Dividend Equivalent Awards may be granted to employees of the Company and its subsidiaries.
B.The Company desires to grant to Employee Performance Shares and Dividend Equivalents under the terms of the Plan.
C.Pursuant to the Plan, the Company and Employee agree as follows:
AGREEMENT
a.Grant of Award. Pursuant to action of the Committee, which was taken on the Date of Grant, the Company grants to Employee ____________ (____) Performance Shares and related Dividend Equivalents. The Performance Shares granted under this Section 1 are referred to in this Award Agreement as the “Base Grant.”
b.Award Subject to Plan. This Performance Share Award and the related Dividend Equivalent Award are granted under and are expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control.
c.Performance Period. The Performance Period for this Award begins January 1, ____________, and ends December 31, ____________.
d.Payment and Vesting.
(i)Performance Shares Payable In Stock. As soon as practicable in the fiscal year immediately following the end of the Performance Period, the Company will determine (i) the Company’s Total Shareholder Return (as defined herein) as compared to the Total Shareholder Return of the companies in the Edison Electric Institute Index (the “Growth Index”) over the Performance Period and (ii) the Company’s Average Performance with respect to the Performance Metrics (as defined herein). The Company then will deliver to Employee one (1) share of the Company’s Stock for each then-outstanding Performance Share under this Award Agreement, subject to adjustment pursuant to Section 5 below. The Company anticipates that the Stock payout, if any, related to the Company’s Total Shareholder Return will be made by ____________. The Company anticipates that the Stock payout, if any, related to the Performance Metrics will be made by ____________ and in no event will such Stock payout be made later than ____________.
(ii)Normal or Early Retirement, Death or Disability; Late Career Recipient.
(i) Provided that Employee either qualifies for “Early Retirement” or “Normal Retirement” under the Pinnacle West Capital Corporation Retirement Plan (the “Retirement Plan”), or is a Late Career Recipient (as defined below), in the case of Employee’s death or Disability, Employee shall be deemed to have been employed by the Company through the end of the Performance




Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(ii) In the case of Employee’s Termination of Employment during the Performance Period which constitutes an Early Retirement or a Normal Retirement under the Retirement Plan, Employee shall be deemed to have been employed by the Company through the end of the Performance Period and Employee (or his or her estate) will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(iii) If, at the time of Employee’s death, Disability or retirement Employee has reached sixty (60) years of age and has been credited with at least five (5) Years of Service, as defined under the Retirement Plan, and does not otherwise meet the criteria for Early Retirement or Normal Retirement under the Retirement Plan, Employee shall be treated for purposes of this Agreement as a “Late Career Recipient”. Upon a Late Career Recipient’s retirement during the Performance Period, Employee will receive a straight prorated payout of the number of Performance Shares calculated in accordance with Section 5 based on the number of days Employee was employed during the Performance Period. Upon a Late Career Recipient’s retirement following the end of the Performance Period, Employee will receive a payout of the number of Performance Shares calculated in accordance with Section 5. No fractional Stock shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock. Employee will receive the Stock, if any, to which Employee is entitled at the time specified in Section 4(a).
(iii)Termination Without Cause. In the event Employee’s employment is terminated by the Company without cause, the Chief Executive Officer (“CEO”) of the Company may determine in his discretion if, to what extent, and when any unvested portion of the Performance Shares granted under this Agreement should vest; provided, however, that (i) any vesting of unvested Performance Shares granted under this Agreement pursuant to this Section 4(c) shall be approved by the Committee, and (ii) nothing herein shall obligate the CEO to exercise his discretion to cause any unvested Performance Shares to vest.
(iv)Termination For Cause. Notwithstanding any other provision in this Section 4, in the event Employee is terminated for Cause, then regardless of Employee’s retirement, Early Retirement, Normal Retirement, death or Disability, Employee shall forfeit the right to receive any Stock hereunder that Employee would otherwise be entitled to receive following his or her date of termination. For purposes only of this Section 4(d), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the CEO reflects adversely on the business or reputation of the Company or any of its subsidiaries or negatively affects any of the Company’s or any of its subsidiaries employees or customers.
(v)Disability. “Disability” has the meaning set forth for such term in the Retirement Plan.
(vi)Dividend Equivalents. In satisfaction of the Dividend Equivalents Award made pursuant to Section 1, at the time of the Company’s delivery of Stock to Employee pursuant to this Section 4, the Company also will deliver to Employee fully transferrable shares of Stock equal in value to the amount of dividends, if any, that Employee would have received if Employee had directly owned the Stock to which the Performance Shares relate from the Date of Grant to the date of the Stock payout, plus interest on such amount at the rate of 5 percent compounded quarterly, as determined pursuant to the Plan. The number of shares of Stock distributed to Employee will be determined by dividing the amount of the Dividend Equivalents and interest by the Fair Market Value of one share of Stock as of the applicable date of the Stock payout. No fractional Stock
2


shall be issued. If the Stock payout results in a fractional share of one-half or greater, such fraction will be increased to provide for the issuance of a full share of Stock.
(vii)Impact on Retirement Plans. The value of the shares of Stock distributed upon payment for the Performance Shares and Dividend Equivalents will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans.
e.Performance Criteria and Adjustments. Fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(a) and fifty percent (50%) of the Performance Shares awarded under this Award Agreement will be determined pursuant to Section 5(b). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Award Agreement greater than 2.0 times the Base Grant.
(i)Adjustment of Base Grant for Total Shareholder Return. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Total Shareholder Return” as compared to the Total Shareholder Return of the companies in the Growth Index during the Performance Period, as follows:
If the Company’s Total Shareholder Return Over The Performance Period As Compared to the Total Shareholder Return of the Companies in the Growth Index is:

The Number of Performance Shares will be:
90th Percentile or greater
75th Percentile
1.0 X Base Grant
.75 X Base Grant
50th Percentile 0.5 X Base Grant
25th Percentile 0.25 X Base Grant
Less than 25th Percentile None
If intermediate percentiles are achieved, the number of Performance Shares awarded will be prorated (partial shares will be rounded down to the nearest whole share when applicable). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection 5(a) greater than 1.0 times the Base Grant.
(ii)Adjustment of Base Grant for Performance Metrics. Fifty percent (50%) of the Base Grant will increase or decrease based upon the Company’s “Average Performance” with respect to the “Performance Metrics,” as follows:
If the Company’s Average Performance is:
The Number of Performance Shares will be:

90th Percentile or greater
75th Percentile
1.0 X Base Grant
.75 X Base Grant
50th Percentile 0.5 X Base Grant
25th Percentile 0.25 X Base Grant
Less than 25th Percentile None
If intermediate percentiles are achieved, the number of Performance Shares awarded pursuant to this Subsection 5(b) will be prorated (partial shares will be rounded down to the nearest whole share when applicable). In no event will Employee be entitled to receive a number of Performance Shares pursuant to this Subsection (b) greater than 1.0 times the Base Grant.
3


f.Definitions.
(i)Performance Metrics. The “Performance Metrics” for the Performance Period are: (i) the System Average Interruption Frequency Index (Major Events Excluded) (“SAIFI”); (ii) Arizona Public Service Company’s customer to employee improvement ratio; (iii) the OSHA rate (All Incident Injury Rate); (iv) nuclear capacity factor; and (v) the J.D. Power Electric Utility Residential Study Overall Customer Satisfaction Index.
(1)With respect to the Performance Metric described in clause (i) of this Subsection 6(a), the Edison Electric Institute (“EEI”) will provide data on an annual basis regarding the SAIFI result of the participating companies; the Company will calculate its SAIFI result for the year in question and determine its percentile ranking based on the information provided by EEI.
(2)With respect to the Performance Metric described in clause (ii) of this Subsection 6(a), S&P Global Market Intelligence (“Market Intelligence”), an independent third party data system, will provide data on an annual basis regarding the customer and employee counts; the Company will use its customer and employee counts for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those companies whose customers and employees were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.
(3)With respect to the Performance Metric described in clause (iii) of this Subsection 6(a), EEI will provide data on an annual basis regarding the OSHA rate of the participating companies; the Company will calculate its OSHA rate for the year in question and determine its percentile ranking based on the information provided by EEI.
(4)With respect to the Performance Metric described in clause (iv) of this Subsection 6(a), Market Intelligence will provide data on an annual basis regarding the nuclear capacity factors of the participating nuclear plants; the Company will calculate its nuclear capacity factor for the year in question and determine its percentile ranking based on the information provided by Market Intelligence. Only those plants that were included in the data provided by Market Intelligence in each of the years of the Performance Period will be considered.
(5)With respect to the Performance Metric described in clause (v) of this Subsection 6(a), the J.D. Power Electric Utility Residential Study will provide data on an annual basis regarding the scores of the participating companies; the Company will calculate its percentile ranking within the large, investor-owned utility peer set based on the information provided by J.D. Power.
(6)The Company’s percentile ranking during the Performance Period for each Performance Metric will be the average of the Company’s percentile ranking for each Performance Metric during each of the three years of the Performance Period (each, an “Average Performance Metric”); provided, however, that if the third year of a Performance Metric is not calculable by December 15 of the following year, the Performance Metric shall consist of the three most recent years for which such Performance Metric is calculable. The Company’s “Average Performance,” for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b) above will be the average of the Average Performance Metrics. If only quartile, rather than percentile, rankings are available for a particular Performance Metric, the Average Performance Metric for any such Performance Metric shall be expressed as a percentile. For example, if the Performance Metric was in the top quartile for two Performance Periods and in the lowest quartile in the other
4


Performance Period, the average of these quartiles would be 3 (the average of 4, 4, and 1) and the Average Performance Metric would be the 75th percentile (3 /4). The calculations in this Subsection 6(a)(6) will be verified by the Company’s internal auditors.
(7)If either EEI or Market Intelligence discontinues providing the data specified above, the Committee shall select a data source that, in the Committee’s judgment, will provide data most comparable to the data provided by EEI or Market Intelligence, as the case may be. If the J.D. Power Electric Utility Residential Customer Satisfaction Study (or a successor JD Power survey) is not available during each of the years of the Performance Period, the Performance Metric associated with the JD Power Residential Survey (Subsection 6(a)(5)) will be disregarded and not included in the Company’s Average Performance for purposes of determining any Base Grant adjustments pursuant to Subsection 5(b).
(ii)Total Shareholder Return. “Total Shareholder Return” for the Performance Period is the measure of a company’s stock price appreciation plus any dividends paid during the Performance Period. Only those companies that were included in the Growth Index in each of the years of the Performance Period will be considered. Total Shareholder Return for the Company and the companies in the Growth Index will be determined using the Daily Comparative Return as calculated by Bloomberg (or other independent third party data system). If the Growth Index is discontinued, the Committee shall select the most comparable index then in use for the sector comparison. In addition, if the sector comparison is no longer representative of the Company’s industry or business, the Committee shall replace the Growth Index with the most representative index then in use. Once the Total Shareholder Returns of the Company and all relevant companies in the Growth Index have been determined, the member companies will be ranked from greatest to least. Percentiles will be calculated (interpolated from 0% to 100%) based on a company’s relative ranking. Percentiles will be carried out to one (1) decimal place. If the Company is not in the Growth Index, then its percentile will be interpolated between the companies listed in the relative ranking. These calculations will be verified by the Company’s internal auditors.
g.Termination of Award. This Award Agreement will terminate and be of no further force or effect on the date that Employee is no longer employed by the Company or any of its subsidiaries, whether due to voluntary or involuntary termination, death, retirement, Disability, or otherwise, except as specifically set forth in Section 4 above or in Article 15 of the Plan. Employee will, however, be entitled to receive any Stock and Dividend Equivalents payable under Section 4 of this Award Agreement if Employee’s employment terminates after the end of the Performance Period but before Employee’s receipt of such Stock and Dividend Equivalents.
h.Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement.
i.Tax Withholding. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout of Stock hereunder by having the Company withhold shares of Stock from such payout.
5


j.Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its subsidiaries.
k.Confidentiality. During Employee’s employment and after termination thereof, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically required by law; provided, however, that in the event disclosure is required by applicable law, Employee shall provide the Company with prompt notice of such requirement, prior to making any disclosure, so that it may seek an appropriate protective order.
Employee agrees that all Confidential Information of the Company and its Affiliates (whether now or hereafter existing) conceived, discovered or made by him during employment exclusively belongs to the Company or its Affiliates (and not to Employee). Employee will promptly disclose such Confidential Information to the Company and perform all actions reasonably requested by the Company to establish and confirm such exclusive ownership. For purposes of this Section 11, the term “Confidential Information” shall mean and include any information disclosed to Employee any time during Employee’s employment with the Company or its Affiliates or thereafter which is not generally known to the public, including, but not limited to, information concerning the Company’s or its Affiliates’ assets and valuations, business plans, methods of operation, management, information systems, procedures, processes, practices, policies, plans, programs, personnel and/or reports or other information prepared by appraisers, consultants, advisors, bankers or attorneys.
l.Restrictive Covenants.
(i)Non-Competition.  Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability),  Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity. 
(ii)Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s Termination of Employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees.
(iii)[No Pledging or Hedging. Employee agrees that during his or her term of employment, Employee will not pledge, margin, hypothecate, hedge, or otherwise grant an economic interest in any shares of Company stock received by Employee pursuant to this Award (net of shares sold or surrendered to meet tax withholding or exercise requirements). This restriction shall extend to
6


the purchase or creation of any short sales, zero-cost collars, forward sales contracts, puts, calls, options or other derivative securities in respect of any shares of Company stock.]
(iv)Remedies. If Employee fails to comply with Sections 11, 12(a), [or] 12(b), [or 12(c)] in a material respect, the Company may (i) cause any of Employee’s unvested Performance Shares and related Dividend Equivalents to be cancelled and forfeited, (ii) refuse to deliver shares of Stock or cash in exchange for vested Performance Shares or Dividend Equivalents, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief.
m.Cooperation with Government Agencies. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically permitted by law, because Employee is providing information to government investigatory or enforcement agencies, such as the Nuclear Regulatory Commission, Department of Labor, Equal Employment Opportunity Commission (or its state equivalent), National Labor Relations Board, the Occupational Safety and Health Administration (or its state equivalent) or the Securities and Exchange Commission. This Award Agreement also does not limit Employee’s ability to communicate with any government agency regarding matters within the agency’s jurisdiction or otherwise participate in any investigation or proceedings that may be conducted by such agency, including providing documents or other information without notice to the Company. Nothing in this Award Agreement shall prevent Employee from the disclosure of Confidential Information or trade secrets that: (i) is made: (a) in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney; and (b) solely for the purpose of reporting or investigating a suspected violation of law; or (ii) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is permitted to be made, and is made, under seal. In the event that Employee files a lawsuit alleging retaliation by Company for reporting a suspected violation of law, Employee may disclose Confidential Information or trade secrets related to the suspected violation of law or alleged retaliation to Employee’s attorney and use the Confidential Information or trade secrets in the court proceeding if Employee or Employee’s attorney: (i) files any document containing Confidential Information or trade secrets, under seal if permitted; and (ii) does not disclose the Confidential Information or trade secrets, except pursuant to or in accordance with a court order. The Company provides this notice in compliance with federal law, including the Defend Trade Secrets Act of 2016.
n.Clawback. The portion of this Award, if any, that is earned based on the Company’s Total Shareholder Return will be subject to potential forfeiture or recovery to the extent called for by the Company’s Clawback Policy. The Clawback Policy may include such provisions as the Human Resources Committee of the Board of Directors determines to be necessary or appropriate either to comply with any applicable law or listing standard or in light of Company ethics or other policies and practices. Specific requirements of the Clawback Policy may be adopted and amended at such times as the Human Resources Committee of the Board of Directors determines in its discretion. By accepting this Award, Employee consents and agrees to abide by such Clawback Policy.
o.Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan.
p.Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan prospectus.
q.Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the
7


benefits under the Plan to qualify for favorable tax treatment either for the Company or Employee or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan.
r.Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together will constitute one and the same instrument. Counterpart signature pages to this Agreement transmitted by facsimile transmission, by electronic mail in portable document format (.pdf), or by any other electronic means will have the same effect as physical delivery of the paper document bearing an original signature.
IN WITNESS WHEREOF, the Company has caused this Award Agreement to be executed, as of the Date of Grant, by an authorized representative of the Company and this Award Agreement has been executed by Employee.
PINNACLE WEST CAPITAL CORPORATION
By: ________________________________

Its: ________________________________
                        Date: _______________________________

EMPLOYEE

By:                        

Date: ___________________________________

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Exhibit 21.1

SUBSIDIARIES LIST

Arizona Public Service Company


*All other subsidiaries of Pinnacle West Capital Corporation and all subsidiaries of Arizona Public Service Company have been omitted as they do not constitute significant subsidiaries within the meaning of Rule 1-02(w) of Regulation S-X.



Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 333‐224366 and 333‐239238 on Form S‐3 and Registration Statement Nos. 333‐143432, 333‐182427, and 333‐157151 on Form S‐8 of our report dated February 24, 2021, relating to the consolidated financial statements of Pinnacle West Capital Corporation and subsidiaries, and the effectiveness of Pinnacle West Capital Corporation and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10‐K for the year ended December 31, 2020.

/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 24, 2021




Exhibit 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333‐224366‐01 on Form S‐3 and Registration Statement Nos. 333‐46161 and 333‐158774 on Form S‐8 of our report dated February 24, 2021, relating to the consolidated financial statements of Arizona Public Service Company and subsidiaries, and the effectiveness of Arizona Public Service Company and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10‐K for the year ended December 31, 2020.

/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 24, 2021




Exhibit 31.1
CERTIFICATION
I, Jeffrey B. Guldner, certify that:
1.    I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;
2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)    evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)    disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the
1



audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: February 24, 2021
/s/ Jeffrey B. Guldner
Jeffrey B. Guldner
Chairman of the Bord of Directors, President and Chief Executive Officer





                                                
                        
2


Exhibit 31.2
CERTIFICATION
I, Theodore N. Geisler, certify that:
1.    I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)    evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)     disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the
1


audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    February 24, 2021

/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and Chief Financial Officer



                        
                        
                        
2

Exhibit 31.3
CERTIFICATION
I, Jeffrey B. Guldner, certify that:
1.I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)    evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)     disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the
2


audit committee of the registrant's board of directors (or persons performing the equivalent functions):
a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date:    February 24, 2021

/s/ Jeffrey B. Guldner
Jeffrey B. Guldner
Chairman of the Board of Directors and
Chief Executive Officer


                    
2

Exhibit 31.4
CERTIFICATION
I, Theodore N. Geisler, certify that:
1.    I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;
2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)    designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)    designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)    evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)    disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the
2


audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    February 24, 2021

/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and Chief Financial Officer

2

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
    I, Jeffrey B. Guldner, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date:    February 24, 2021

/s/ Jeffrey B. Guldner
Jeffrey B. Guldner
Chairman of the Board of the Directors, President and
Chief Executive Officer
    I, Theodore N. Geisler, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date:    February 24, 2021

/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and Chief Financial Officer





CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
    I, Jeffrey B. Guldner, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date:    February 24, 2021

/s/ Jeffrey B. Guldner
Jeffrey B. Guldner
Chairman of the Board of Directors and
Chief Executive Officer
    I, Theodore N. Geisler, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date:    February 24, 2021

/s/ Theodore N. Geisler
Theodore N. Geisler
Senior Vice President and Chief Financial Officer