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, 20192022
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 COMPANYCommon 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“large accelerated filer," "accelerated” “accelerated filer," "smaller” “smaller reporting company,"” and "emerging“emerging growth company"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 | $ | 10,536,165,750 | as of June 30, 2019 | ||
| ARIZONA PUBLIC SERVICE COMPANY | $ | 0 | as of June 30, 2019 | ||
| PINNACLE WEST CAPITAL CORPORATION | $ | 8,247,902,707 | as of June 30, 2022 | ||||||||
| ARIZONA PUBLIC SERVICE COMPANY | $ | 0 | as of June 30, 2022 | ||||||||
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 | |||||||
| ARIZONA PUBLIC SERVICE COMPANY | Number of shares of common stock, $2.50 par value, outstanding as of February | 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 20, 202017, 2023 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
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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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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 | ||||
| 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 | ||||
| DC | Direct Current | ||||
| distributed renewable energy systems or DG | 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 | ||||
| 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 | ||||
| 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) | ||||
| Power | |||||
| Power Supply Adjustor | |||||
| 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 | ||||
| Time of Use | |||||
| TEAM | Tax expense adjustor mechanism | ||||
| VIE | Variable interest entity | ||||
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FORWARD-LOOKING STATEMENTS
This document contains forward-looking statements based on current expectations. These forward-looking statements are often identified by words such as "estimate," "predict," "may," "believe," "plan," "expect," "require," "intend," "assume," "project"“estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” “anticipate,” “goal,” “seek,” “strategy,” “likely,” “should,” “will,” “could,” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:
•the current economic environment and its effects, such as lower economic growth, a tight labor market, inflation, supply chain delays, increased expenses, volatile capital markets, or other unpredictable effects;
•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 (including large increases in ambient temperatures), the general economy or social conditions, customer, and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;
•the potential effects of climate change on our electric system, including as a result of weather extremes such as prolonged drought and high temperature variations in the area where APS conducts its business;
•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 or interpretations of existing legislation or regulations, 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;Arizona;
•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;delivery, including as a result of delays in the development and application of new technologies;
•the cost of debt, including increased cost as a result of rising interest rates, 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 gasGHG emissions;
•volatile fuel and purchased power costs;
•the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;
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•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;
•generation, transmission and distribution facility and system conditions and operating costs;
•the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;
•the willingness or ability of our counterparties, power plant participants and power plant land ownerslandowners to meet contractual or other obligations or continue or discontinueextend the rights for continued power plant operations consistent with our corporate interests;operations; and
•restrictions on dividends or other provisions in our credit agreements and ACC orders.
These and other factors are discussed in the Risk Factors described in Item 1A of this report, and in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this
report, which readers should review carefully before placing any reliance on our financial statements or disclosures. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.
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PART I
ITEM 1. BUSINESS
Pinnacle West
Pinnacle West is a holding company that conducts business through its subsidiaries. We derive essentially all of our revenues and earnings from our wholly-owned subsidiary, APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the State of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.
Pinnacle West’s other subsidiaries are El Dorado, BCE and 4CA. Additional information related to these subsidiaries is provided later in this report.
Our reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission, and distribution.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
APS currently provides electric service to approximately 1.3 million customers. We own or lease 6,3166,340 MW of regulated generation capacity and we hold a mix of both long-term and short-term purchased power agreements for additional capacity, including a variety of agreements for the purchase of renewable energy. During 2019,2022, no single purchaser or user of energy accounted for more than 1.7%2.4% of our electric revenues.
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The following map shows APS’s retail service territory, including the locations of its generating facilities and principal transmission lines.
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Energy Sources and Resource Planning
To serve its customers, APS obtains power through its various generation stations and through purchased power agreements. Resource planning is an important function necessary to meet Arizona’s future energy needs. APS’s sources of energy by type used to supply energy to Native Load customers during 20192022 were as follows:
* When including APS’s historicalRenewables include energy efficiencyfrom wind, solar, geothermal, biomass, DG, and distributed generation energy contributions, thesolar PPAs.
The share of our customers’APS’s energy supply being derived from clean resources is 51%.
BCE also has acquired minority ownership positions in two wind farms that achieved commercial operation in 2020. Both wind farms deliver power under long-term PPAs. See “Business of Other Subsidiaries — Bright Canyon Energy” below for information regarding BCE’s investments.
Clean Energy Focus Initiatives
In response to climate change, the entire electric utility industry, as well as the global economy, is in the midst of a profound transition to clean energy and a new low-carbon economy. APS has undertaken a number of initiatives to address emission concerns,reduce carbon, including renewable energy procurement and development, and promotion of programs and rates that promote energy conservation, renewable energy use, and energy efficiency. (SeeSee “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,
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including solar, wind, geothermal, biogas, and biomass. In addition, in January 2020, APS recently announced its Clean Energy Commitment, a three-pronged approach aimed at ultimately eliminating carbon-emitting resources from its electric generation resource portfolio.
APS’s Clean Energy Commitment consistsclean energy goals consist of three parts. First, APS announced an aspirationalparts:
•a 2050 goal to generate electricity with zero-carbon emissions by 2050. Second, APS announced provide 100% clean, carbon-free electricity;
•a nearer-term 2030 target of achieving a resource mix that is 65% clean energy, with 45% of APS'sthe generation portfolio coming from renewable energy. Third, APS committedenergy; and
•a commitment to
Among other strategies, APS intends to achieve these goals through various methods such as relying on Palo Verde, the nation’s largest producer of carbon-free energy; increasing clean energy resources, including renewables; developing energy storage; cease buying coal-generation;ceasing the use of coal-generated electricity; managing demand with a modern interactive grid; promoting customer technology and energy efficiency; and optimizing regional resources. (SeeManagement takes into consideration climate change and other environmental risks in its strategy development, business planning, and enterprise risk management processes. See Item 7, "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operation"Operations” for additional information about ourAPS’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'sAPS’s operations. Among other resiliency strategies, APS anticipates increasing investments in a modern and more flexible electricity grid with advanced distribution technologies. Moreover, APS plans to continue its comprehensive forest management programs aimed at reducing wildfires, as those risks become compounded by shorter, drier winters and longer, hotter summers.summers as a result of climate change.
APS prepares an annual inventory of GHG emissions from its operations. For APS'sAPS’s operations involving fossil-fuel electricity generation and electricity transmission and distribution, APS'sAPS’s annual GHG inventory is reported to EPA under the EPA GHG Reporting Program. APS also voluntarily tracks the full scope of the Company'sAPS’s GHG emissions arising from all APS operations. In addition to reporting to the EPA, we publicly report Scope 1, 2 and 3 GHG emissions from generation and transmission and distribution operations, this data includes all other GHG emissions arising from ancillary Company operations, such as vehicle use, employee travel, portable generators and facility energy usage.emissions. This data is then communicated to the public in Pinnacle West’s annual Corporate Responsibility Report as performance data and in CDP Reports, which isare available on our website (www.pinnaclewest.comwww.pinnaclewest.com/corporate-responsibility). The report providesreports provide information related to the Company and its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report,Reports and CDP Reports, is not incorporated by reference into or otherwise a part of this report.
Generation Facilities
APS has ownership interests in or leases the coal, nuclear, gas, oil, coal, and solar generating facilities as well as energy storage facilities described below. For additional information regarding these facilities, see Item 2.
Nuclear
Palo Verde Generating Station — Palo Verde is a 3-unit nuclear power plant located approximately 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3
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and approximately 17% of Unit 2. In addition, APS leases approximately 12.1% of Unit 2, resulting in a 29.1% combined ownership and leasehold interest in that unit. APS has a total entitlement from Palo Verde of 1,146 MW.
Palo Verde Leases — In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back approximately 42% of its share of Palo Verde Unit 2 and certain common facilities. The leaseback was originally scheduled to expire at the end of 2015 and contained options to renew the leases or to purchase the leased property for fair market value at the end of the lease terms. On July 7, 2014, APS exercised the fixed rate lease renewal options. The exercise of the renewal options originally resulted in APS retaining the assets through 2023 under one lease and 2033 under the other two leases. On April 1, 2021, APS executed an amendment relating to the lease agreement with the term ending in 2023. The amendment extends the lease term for this lease through 2033 and changes the lease payment. As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements. At the end of the lease renewal periods, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors. See Note 1917 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 20252028 and 30%48% through 2028;2029; 100% of Palo Verde’s requirements for conversion services through 2025,2030 and 40% through 2030;2031; 100% of Palo Verde’s requirements for enrichment services through 2021, 90%2026 and 28% for 2022, and 80% for 2023 through 2026;2027; and 100% of Palo Verde’s requirements for fuel fabrication through 2027.2027 for Unit 2 and Unit 1 and 2028 for Unit 3.
Spent Nuclear Fuel and Waste Disposal — The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to begin to accept, transport, and dispose of spent nuclear fuel and high levelhigh-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
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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 DOE’s failure to meet its statutory and contractual obligations regarding acceptance of spent nuclear fuel and high levelhigh-level waste.
APS Lawsuit for Breach of Standard Contract — In December 2003, APS, acting on behalf of itself and the Palo Verde participants, filed a lawsuit against the DOE in the United States Court of Federal Claims ("(“Court of Federal Claims"Claims”) for damages incurred due to the DOE’s breach of the Standard Contract. The Court of Federal Claims ruled in favor of APS and the Palo Verde participants in October 2010 and awarded damages to APS and the Palo Verde participants for costs incurred through December 2006.
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the Court of Federal Claims. This lawsuit sought to recover damages incurred due to the DOE’s breach of the Standard Contract for failing to accept Palo Verde’s
spent nuclear fuel and high levelhigh-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 providesprovided APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2016, which was extended to December 31, 2019.2022. An additional extension is currently pending.
APS has submitted and received payment for fiveeight claims pursuant to the terms of the August 18, 2014 settlement agreement for fiveeight separate time periods during July 1, 2011 through June 30, 2018.2021. The DOE has approved and paid $84.3$123.9 million for these claims (APS’s share is $24.5$36 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS's nextIn accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers. See Note 3. On October 31, 2022, APS filed its ninth claim pursuant to the terms of the August 18, 2014, settlement agreement was submitted to the DOE on October 31, 2019 in the amount of $16 million (APS's share is $4.7 million). On February 11, 2020, the DOE approved a payment of $15.4$14.3 million (APS’s share is $4.5$4.2 million). In February 2023, the DOE approved this claim.
Waste Confidence and Continued Storage — On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high levelhigh-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s waste confidence decision and temporary storage rule (“Waste Confidence Decision”). The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA.National Environmental Policy Act. In September 2013, the NRC issued its draft Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed as the Continued Storage Rule, the NRC’s decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be
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re-analyzed in the environmental reviews for individual licenses. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continued Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate 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 specificsite-specific decommissioning costs for Palo Verde at the time the units are expected to be decommissioned. See Note 2018 for additional information about APS’s nuclear decommissioning trusts.
Palo Verde Liability and Insurance Matters — See “Palo Verde Generating Station — Nuclear Insurance” in Note 1110 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. GasA portion of the gas for these plants is financially hedged up to fivethree years in advance of purchasing and thethat position is converted to a physical gas is generally purchasedpurchase one month prior to delivery. APS has long-term gas transportation agreements with three different companies, some of which are effective through 2027.2049. Fuel oil is acquired under short-term purchases delivered by truck directly to the power plants.
Ocotillo was originally a 330 MW 4-unit gas plant located in the metropolitan Phoenix area.Tempe. In early 2014, APS announced a project to modernize the plant, which involved retiring two older 110 MW steam units, adding five 102 MW combustion turbines, and maintaining two existing 55 MW combustion turbines. In total, this increased the capacity of the site by 290 MW to 620 MW. (See Note 4 for rate recovery as part of the ACC final written Opinion and Order issued reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision")). The Ocotillo modernization project was completed in 2019.
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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 West, owned 7% of Units 4 and 5 from July 2016 through July 2018 following its acquisition of El Paso'sPaso’s interest in these units described below. As part of APS's recently announcedAPS’s Clean Energy Commitment, APS has committed to eliminatecease using coal-fired generation fromas part of its portfolio of electricity generating resources, including Four Corners, by 2031.
NTEC, a company formed by the Navajo Nation to own the mine that serves Four Corners and develop other energy projects, is the coal supplier for Four Corners. The Four Corners’ co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016 through 2031 (the "2016“2016 Coal Supply Agreement"Agreement”). El Paso, a 7% owner of Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS agreed to assume the 7% shortfall obligation. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso'sPaso’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's4CA’s 7% interest in Four Corners. NTEC assumed 4CA’s reclamation and decommissioning obligations associated with the 7% interest. The sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million and is paying 4CApaid the purchase price over a
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 extendingto extend the life of the plant and the adjacent mine.
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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 operatesoperated that unit for PacifiCorp. On September 11, 2014, APS announced that it would close its 260 MWCholla Unit 2 at Cholla and cease burning coal at Unitsthe other APS-owned units (Units 1 and 33) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS'sAPS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS'sAPS’s remaining investment in the Unit, which was later addressed in the March 27, 2017 settlement agreement regarding APS's general retail case (the "2017 Settlement Agreement"). (See Note 4 for details related to the resulting regulatory asset and allowed recovery set forth in the 2017 Settlement Agreement.) APS believes that the environmental benefits of this proposal are greater in the long-term than the benefits that would have resulted from adding the emissions control equipment.Unit. APS closed Unit 2 on October 1, 2015. Following the closure of Unit 2, APS has a total entitlement from Cholla of 387381 MW. In early 2017, EPA
approved a final rule incorporating APS'sAPS’s compromise proposal, which took effect for Cholla on April 26, 2017. In December 2019, PacifiCorp notified APS that it plansplanned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020. APS has committed to end the use of coal at its remaining Cholla units by 2025.
APS purchases all of Cholla’s coal requirements from a coal supplier that mines all of the coal under long-term leases of coal reserves with the federal and state governments and private landholders. The Cholla coal contract runs through 2024. In addition, APS has a coal transportation contract that runs through 2020, with the ability to extend the contract annually through 2024.
Navajo Plant — The Navajo Plant iswas a 3-unit coal-fired power plant located in northern Arizona. Salt River Project operatesoperated the plant and APS ownsowned a 14% interest in Units 1, 2 and 3. APS had a total entitlement from the Navajo Plant of 315 MW. The Navajo Plant’s coal requirements were purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Plant was under contract with its coal supplier through 2019, with extension rights through 2026. The Navajo Plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allowswhich 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 (seeplant. See Note 43 for details related to the resulting regulatory asset)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 1110 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 170180 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 4044 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
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Arizona. APS has also developed solar photovoltaic distributed renewable energy systems installed as part of the Community Power Project in Flagstaff, Arizona. The Community Power Project, approved by the ACC on April 1, 2010, was a pilot program through which APS owns, operates, and receives energy from approximately 1 MW of solar photovoltaic distributed renewable energy systems located within a certain test area in Flagstaff, Arizona. The pilot program is now complete and as part of the 2017 Rate Case Decision, the participants have been transferred to the Solar Partner Program described below. Additionally, APS owns 13 MW of solar photovoltaic systems installed across Arizona through the ACC-approved Schools and Government Program.
In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar“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'sAPS’s rate base as part of the 2017 Rate Case Decision.
In the 2017 Rate Case Decision, the ACC also approved the "APS“APS Solar Communities"Communities” program. APS Solar Communities (formerly AZ Sun II) is a three-year program authorizing APS to spend $10 million -to $15 million in capital costs each year to install utility-owned distributed generationDG 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 511 MW of distributed generationDG systems under the APS Solar Communities program. In the 2019 Rate Case decision, the ACC authorized APS to spend $20 million to $30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the decision.
Energy Storage
APS deploys a number of advanced technologies on its system, including energy storage. Storage can provideEnergy storage provides capacity, improveimproves power quality, can be utilized for system regulation integrate renewable generation, and, canin certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aidaids in integrating higher levels of renewablesrenewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, tomeet customer reliability requirements, 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.
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Additionally, in February 2019, APS signed two 20-year power purchase agreementsPPAs for energy storage totaling 150 MW. Service under these power purchase agreements is also dependent on the results of the McMicken battery incident investigation and requiresThese PPAs were subject to ACC approval from the ACCin order to allow for cost recovery through the PSA.APS received the requested ACC approval on January 12, 2021, and service under the agreements is expected to begin in 2023.
In December 2020, APS issued two RFPs (collectively, the “December 2020 RFPs”). As a result of thesethe December 2020 RFPs, APS executed four 20-year PPAs for resources that include energy storage: (a) two PPAs for standalone energy storage resources totaling 300 MW; and (b) two PPAs for solar plus storage resources totaling 275 MW. The PPAs are also subject to ACC approval to enable cost recovery through the PSA. APS received the requested ACC approval for three out of four of the projects on December 16, 2021 and on April 13, 2022 for the remaining project. Service under the agreements is expected to begin in 2023 and 2024.
In May 2022, APS issued an RFP to address resource needs for 2025 and beyond (the “2022 RFP”). As a result of the 2022 RFP, as of January 2023, APS has executed a 20-year PPA for solar plus storage resources totaling 300 MW. The PPA is subject to ACC approval to enable cost recovery through the PSA, (See Note 4 for details relatedwhich was requested in December 2022 and approved in February 2023. Service under this agreement is expected to the PSA).begin in 2025.
The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2022.Agreements for the development and completion of future resources are subject to various conditions.
Net Capacity in Operation (MW) | Net Capacity Planned / Under Development (MW) | ||||||||||
| APS Owned Energy Storage | — | 201 | |||||||||
| PPAs Energy Storage | — | 1,025 | |||||||||
| Residential Energy Storage | 19(a) | 7 | |||||||||
| Total Energy Storage Portfolio | 19 | 1,233 | |||||||||
(a) This includes 18.5 MW of APS customer-owned batteries and 0.2 MW of APS-owned residential batteries.
Renewable Energy Portfolio
To date, APS has a diverse portfolio of existing and planned renewable resources totaling 3,894 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 2,418 MW are currently in operation and 1,476 MW are under contract for development or are under construction. Renewable resources in operation include 264 MW of facilities owned by APS, 736 MW of long-term purchased power agreements, and an estimated 1,418 MW of customer-sited, third-party owned distributed energy resources.
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As previously discussed, in May 2022, APS issued an RFP to address resource needs for 2025 and beyond. The 2022 RFP solicits competitive proposals for approximately 1,000 MW to 1,500 MW of resources, including up to 600 MW to 800 MW of renewable resources to meet the needs of 2025 and 2026 while also considering resources that can be online as late as 2027. The 2022 RFP stopped accepting bids on July 15, 2022, and APS sent notifications to shortlisted bidders on September 23, 2022. As a result of the 2022 RFP, and as of December 31, 2022, APS has signed a PPA for 300 MW of solar plus energy storage projects. Givenresources and a PPA for 216 MW of wind resources. Once APS secures those important resources and closes out the April 2019 event, we continue2022 RFP, APS intends to evaluate the appropriate timingissue APS’s next RFP to address future resource needs.
APS’s strategy to achieve its RES requirements includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and path forwardprocurement of new facilities to support the overall capacity goalsbe owned by APS. See “Energy Sources and Resource Planning — Generation Facilities — Solar Facilities” above for our systeminformation regarding APS-owned solar facilities and associated“Energy Sources and Resource Planning — Generation Facilities — Energy Storage” above for more information regarding APS-owned energy storage requirements. Currently,facilities.
The following table summarizes APS’s renewable energy sources currently in operation and under development as of December 31, 2022. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.
| Location | Actual/ Target Commercial Operation Date | Term (Years) | Net Capacity In Operation (MW AC) | Net Capacity Planned/Under Development (MW AC) | ||||||||||||||||||||||||||||
| APS Owned | ||||||||||||||||||||||||||||||||
| Solar: | ||||||||||||||||||||||||||||||||
| AZ Sun Program: | ||||||||||||||||||||||||||||||||
| Paloma | Gila Bend, AZ | 2011 | 17 | |||||||||||||||||||||||||||||
| Cotton Center | Gila Bend, AZ | 2011 | 17 | |||||||||||||||||||||||||||||
| Hyder Phase 1 | Hyder, AZ | 2011 | 11 | |||||||||||||||||||||||||||||
| Hyder Phase 2 | Hyder, AZ | 2012 | 6 | |||||||||||||||||||||||||||||
| Chino Valley | Chino Valley, AZ | 2012 | 20 | |||||||||||||||||||||||||||||
| Hyder II | Hyder, AZ | 2013 | 14 | |||||||||||||||||||||||||||||
| Foothills | Yuma, AZ | 2013 | 38 | |||||||||||||||||||||||||||||
| Gila Bend | Gila Bend, AZ | 2014 | 36 | |||||||||||||||||||||||||||||
| Luke AFB | Glendale, AZ | 2015 | 11 | |||||||||||||||||||||||||||||
| Desert Star | Buckeye, AZ | 2015 | 10 | |||||||||||||||||||||||||||||
| Subtotal AZ Sun Program | 180 | — | ||||||||||||||||||||||||||||||
| Multiple Facilities | AZ | Various | 4 | |||||||||||||||||||||||||||||
| Red Rock | Red Rock, AZ | 2016 | 44 | |||||||||||||||||||||||||||||
| Agave Solar | Arlington, AZ | 2023 | 150 | |||||||||||||||||||||||||||||
| Distributed Energy: | ||||||||||||||||||||||||||||||||
| APS Owned (a) | AZ | Various | 36 | |||||||||||||||||||||||||||||
| Total APS Owned | 264 | 150 | ||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||
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| Gillespie | Maricopa County, AZ | 2013 | 30 | 15 | ||||||||||||||||||||||||||||
| CO Bar Solar A | Coconino County, AZ | 2023 | 18 | 80 | ||||||||||||||||||||||||||||
| CO Bar Solar B | Coconino County, AZ | 2023 | 18 | 80 | ||||||||||||||||||||||||||||
| Mesquite Solar 5 | Tonopah, AZ | 2023 | 20 | 60 | ||||||||||||||||||||||||||||
| Sunstreams 3 | Arlington, AZ | 2024 | 20 | 215 | ||||||||||||||||||||||||||||
| Sunstreams 4 | Arlington, AZ | 2025 | 20 | 300 | ||||||||||||||||||||||||||||
| Wind: | ||||||||||||||||||||||||||||||||
| Aragonne Mesa | Santa Rosa, NM | 2022 | 20 | 200 | ||||||||||||||||||||||||||||
| High Lonesome | Mountainair, NM | 2009 | 30 | 100 | ||||||||||||||||||||||||||||
| Perrin Ranch Wind | Williams, AZ | 2012 | 25 | 99 | ||||||||||||||||||||||||||||
| Chevelon Butte | Winslow, AZ | 2023 | 20 | 238 | ||||||||||||||||||||||||||||
| Chevelon Butte II | Winslow, AZ | 2024 | 20 | 216 | ||||||||||||||||||||||||||||
| Geothermal: | ||||||||||||||||||||||||||||||||
| Salton Sea | Imperial County, CA | 2006 | 23 | 10 | ||||||||||||||||||||||||||||
| Biomass: | ||||||||||||||||||||||||||||||||
| Snowflake | Snowflake, AZ | 2008 | 25 | 14 | ||||||||||||||||||||||||||||
| Biogas: | ||||||||||||||||||||||||||||||||
| NW Regional Landfill | Surprise, AZ | 2012 | 20 | 3 | ||||||||||||||||||||||||||||
| Total Purchased Power Agreements | 736 | 1,189 | ||||||||||||||||||||||||||||||
| Distributed Energy | ||||||||||||||||||||||||||||||||
Solar (b) | ||||||||||||||||||||||||||||||||
| Third-party Owned | AZ | Various | 1,385 | 137 | ||||||||||||||||||||||||||||
| Agreement 1 | Bagdad, AZ | 2011 | 25 | 15 | ||||||||||||||||||||||||||||
| Agreement 2 | AZ | 2011-2012 | 20-21 | 18 | ||||||||||||||||||||||||||||
| Total Distributed Energy | 1,418 | 137 | ||||||||||||||||||||||||||||||
| Total Renewable Portfolio | 2,418 | 1,476 | ||||||||||||||||||||||||||||||
(a)Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.
(b)Includes rooftop solar facilities owned by third parties. DG is pursuing an RFPproduced in DC and is converted to AC for battery-ready solar resources up to 150 MW with results expected in the first half of 2020.reporting purposes.
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. (SeeSee Note 17.)15. APS continually assesses its need for additional capacity resources to assure system reliability. In addition, APS has also entered into several power purchase agreementsPPAs for energy storage. (See "BusinessSee “Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Energy Storage"Storage” above for details ofon our energy storage power purchase agreements.)PPAs.
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Purchased Power Capacity — APS’s purchased power capacity under long-term contracts as of December 31, 20192022, 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, | |||||||||||||
| Demand Response Agreement | Summer seasons through | |||||||||||||
| Tolling Agreement | May 1 through October 31, 2021-2027 | 463 | ||||||||||||
| Tolling Agreement | Summer seasons from Summer 2020 through Summer 2025 | 565 | ||||||||||||
| Tolling Agreement | June 1 through September 30, 2020-2026 | 570 | ||||||||||||
| Various | 736 | |||||||
(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)Does not include MW of capacity planned or under development. Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio.”
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 20192022 peak one-hour demand on its electric system was recorded on August 5, 2019July 11, 2022, at 7,1157,587 MW, compared to the 20182021 peak of 7,3207,580 MW recorded on July 24, 2018. The reduction was largely driven by milder peak day weather conditions in 2019.June 18, 2021. APS’s reserve margin at the time of the 20192022 peak demand, calculated using system load serving capacity, was 16%13%. For 2020,2023, due to expiring purchased power contracts, APS is procuring market resources to maintain its minimum 15% planning reserve criteria.
Future Resources and Resource Plan
ACC rules require utilities to develop fifteen-year15-year Integrated Resource Plans ("IRP"(“IRP”) which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans. APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows. Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’sIRPs from April 1, 2020, to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. In February 2022, the ACC acknowledged APS’s IRP. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by January 1, 2030. Due to current projected future resource needs and load forecasts, APS continues to need to develop or acquire additional capacity. APS intends to file its next IRP later in 2023.
See "Business“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Clean Energy Focus Initiatives"Initiatives” and "Business“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Energy Storage"Storage” above for information regarding future plans for energy storage. See "Business“Business of Arizona Public Service Company -— Energy Sources and Resource Planning -— Generation Facilities -— Coal-Fueled Generating Facilities"Facilities” above for information regarding plans for Cholla, Four Corners and the Navajo Plant.
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Energy Imbalance Market & Wholesale Market
In 2015,2016, APS and the CAISO, the operator for the majority of California's transmission grid, signed an agreement for APSbegan to begin participationparticipate in the Energy Imbalance Market (“EIM”). APS's participation in, a voluntary, real-time optimization market operated by the EIM began on October 1, 2016.CAISO. The EIM allows for rebalancing supply and demand in 15-minute blocks withand dispatching generation every five minutes, before the energy is needed, instead of the traditional one hourone-hour blocks. 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. APS also is in discussions with Southwest Power Pool, a market operator developing a day-ahead and real-time market for the Western Interconnection. In addition, APS is participating in the Western Resource Adequacy Program administered by the Western Power Pool. These efforts are driven by three objectives of reducing customer cost, improving reliability, and incorporating more clean energy on APS’s system.
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 power was defined as a clean energy resource. The proposed rules also required 50% of retail energy served be renewable by the end of 2035. On November 13, 2020, the ACC approved a final draft energy rules package which required additional procedural steps in the rulemaking process. In June 2021, the ACC adopted clean energy rules based on a series of ACC amendments to the final energy rules. The adopted rules require 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050, and 95% reduction by December 31, 2060. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider All-Source RFP requirements and the IRP process. During the August 2022 ACC Open Meeting, Commissioners voted to postpone a decision on the All-Source RFP and IRP rulemaking package until 2023. APS cannot predict the outcome of this matter. See Note 3 for additional information related to these energy rules.
Renewable Energy Standard
In 2006, the ACC adopted the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas, and geothermal technologies. The renewable energy requirement is 10%13% of retail electric sales in 20202023 and increases annually until it reaches 15% in 2025. In APS’s 2009 general retail rate case settlement agreement (the “2009 Settlement Agreement”), APS committed to use its best efforts to have 1,700 GWh of new renewable resources in service by year-end 2015 in addition to any existing resources or commitments as of the end of 2008. APS met its settlement commitment in 2015.
A component of the RES is focused on stimulating development of distributed renewable energy systems. Accordingly, under the RES, an increasing percentage of that requirement must be supplied from distributed energy resources. This distributed renewable energy requirement, iswhich was waived by the ACC as a part of APS’s 2023 RES Implementation Plan, would have been 30% of the overall RES requirement of 10%13% in 2020.2023. On June 7, 2021, the ACC approved the 2021 RES Implementation Plan. On July 1, 2019,2021, APS filed its 20202022 RES Implementation Plan.Plan, which was subsequently amended on December 9, 2021. On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an
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amendment requiring a stakeholder working group to convene and develop a community solar program for the Commission’s consideration at a future date. On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group. APS is proposing a small, pilot scale program size of up to 140 MW that would be selected through a competitive RFP. The ACC has not yet ruled on the proposal. However, on November 10, 2022, the ACC approved a bifurcated community solar process, directing ACC Staff to develop a statewide policy through additional stakeholder involvement and establishing a separate evidentiary hearing to define other policy components. The community solar program was deferred to the ACC’s Hearing Division so that a formal evidentiary hearing could be held to consider issues of substance related to community solar. APS cannot predict the outcomes of these future activities.
On July 1, 2022, APS filed its 2023 RES Implementation Plan, and on November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023. The following table summarizes the RES requirement standard (not including the additional commitment required by the 2009 Settlement Agreement) and its timing:
| 2023 | 2025 | |||||||||||||
| RES (inclusive of distributed energy) as a percent of retail electric sales | 13% | 15% | ||||||||||||
| Percent of RES to be supplied from distributed renewable energy resources (a) | 30% | 30% | ||||||||||||
(a)The distributed renewable energy requirement has been waived for 2023.
| 2020 | 2025 | |||
| RES (inclusive of distributed energy) as a % of retail electric sales | 10% | 15% | ||
| Percent of RES to be supplied from distributed energy resources | 30% | 30% | ||
On April 21, 2015, the RES rules were amended to require utilities to report on all eligible renewable resources in their service territory, irrespective of whether the utility owns renewable energy credits associated with such renewable energy. The rules allow the ACC to consider such information in determining whether APS has satisfied the requirements of the RES. See "Energy Modernization Plan" in Note 4 for information regarding an additional renewable energy standards proposal.
| Location | Actual/ Target Commercial Operation Date | Term (Years) | Net Capacity In Operation (MW AC) | Net Capacity Planned/Under Development (MW AC) | ||||||||||
| APS Owned | ||||||||||||||
| Solar: | ||||||||||||||
| AZ Sun Program: | ||||||||||||||
| Paloma | Gila Bend, AZ | 2011 | 17 | |||||||||||
| Cotton Center | Gila Bend, AZ | 2011 | 17 | |||||||||||
| Hyder Phase 1 | Hyder, AZ | 2011 | 11 | |||||||||||
| Hyder Phase 2 | Hyder, AZ | 2012 | 5 | |||||||||||
| Chino Valley | Chino Valley, AZ | 2012 | 19 | |||||||||||
| Hyder II | Hyder, AZ | 2013 | 14 | |||||||||||
| Foothills | Yuma, AZ | 2013 | 35 | |||||||||||
| Gila Bend | Gila Bend, AZ | 2014 | 32 | |||||||||||
| Luke AFB | Glendale, AZ | 2015 | 10 | |||||||||||
| Desert Star | Buckeye, AZ | 2015 | 10 | |||||||||||
| Subtotal AZ Sun Program | 170 | — | ||||||||||||
| Multiple Facilities | AZ | Various | 4 | |||||||||||
| Red Rock | Red Rock, AZ | 2016 | 40 | |||||||||||
| Distributed Energy: | ||||||||||||||
| APS Owned (a) | AZ | Various | 26 | |||||||||||
| Total APS Owned | 240 | — | ||||||||||||
| Purchased Power Agreements | ||||||||||||||
| Solar: | ||||||||||||||
| Solana | Gila Bend, AZ | 2013 | 30 | 250 | ||||||||||
| RE Ajo | Ajo, AZ | 2011 | 25 | 5 | ||||||||||
| Sun E AZ 1 | Prescott, AZ | 2011 | 30 | 10 | ||||||||||
| Saddle Mountain | Tonopah, AZ | 2012 | 30 | 15 | ||||||||||
| Badger | Tonopah, AZ | 2013 | 30 | 15 | ||||||||||
| Gillespie | Maricopa County, AZ | 2013 | 30 | 15 | ||||||||||
| Solar + Energy Storage: | ||||||||||||||
| First Solar | Arlington, AZ | 2021 | 15 | 50 | ||||||||||
| Wind: | ||||||||||||||
| Aragonne Mesa | Santa Rosa, NM | 2006 | 20 | 90 | ||||||||||
| High Lonesome | Mountainair, NM | 2009 | 30 | 100 | ||||||||||
| Perrin Ranch Wind | Williams, AZ | 2012 | 25 | 99 | ||||||||||
| Geothermal: | ||||||||||||||
| Salton Sea | Imperial County, CA | 2006 | 23 | 10 | ||||||||||
| Biomass: | ||||||||||||||
| Snowflake | Snowflake, AZ | 2008 | 15 | 14 | ||||||||||
| Biogas: | ||||||||||||||
| NW Regional Landfill | Surprise, AZ | 2012 | 20 | 3 | ||||||||||
| Total Purchased Power Agreements | 626 | 50 | ||||||||||||
| Distributed Energy | ||||||||||||||
Solar (b) | ||||||||||||||
| Third-party Owned | AZ | Various | 929 | 45 | ||||||||||
| Agreement 1 | Bagdad, AZ | 2011 | 25 | 15 | ||||||||||
| Agreement 2 | AZ | 2011-2012 | 20-21 | 18 | ||||||||||
| Total Distributed Energy | 962 | 45 | ||||||||||||
| Total Renewable Portfolio | 1,828 | 95 | ||||||||||||
Demand Side Management
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. (SeeSee Note 43 for information regarding ACC'sACC’s regulation of APS'sAPS’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
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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 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,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 and energy modernization plan proposals 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 staffStaff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC has scheduled a workshop for February 25-26, 2020 for further consideration and discussion of the continues to discuss matters related to retail electric competition, rules.including the potential for additional buy-through programs or other pilot programs. In April 2022, the Arizona Legislature passed and the Governor signed a bill that repealed the electric deregulation law that had been in place in Arizona since 1998. APS cannot predict whether these effortswhat impact, if any, this change will resulthave on APS.
On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in any changesArizona.Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and if changesTucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application and intends to intervene to contest it. On November 3, 2021, the ACC submitted questions to the rules results, what impactOffice of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided insights on the applicable law.
On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier. The letter also states that similar programs should be designed for other Arizona regulated electric utilities. APS cannot predict the outcome of these rules would have on APS.
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Wholesale
FERC regulates rates for wholesale power sales and transmission services. (SeeSee Note 43 for information regarding APS’s transmission rates.) During 2019,2022, approximately 5.3%11.6% of APS’s electric operating revenues resulted from such sales and services. APS’s wholesale activity primarily consists of managing fuel and purchased power supplies to serve retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’s Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS hedges both electricity and fuels.natural gas. The majority of these activities are undertaken to mitigate risk in APS’s portfolio.
Transmission and Delivery
APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, system reliability, access to markets and clean energy development. The capital expenditures table presented in the "Liquidity“Liquidity and Capital Resources"Resources” section of Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this report includes new APS transmission projects, along with other transmission costs for upgrades and replacements, including those for data center and semi-conductor manufacturing development. APS is also working to establish and expand advanced grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better manage their energy usage, minimize system outage durations and frequency, enable customer choice for new customer sited technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distributiondelivery 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 pending climate-change related legislation regulating or limiting utility-sector GHG emissions under consideration in the 116th118th Congress will be considered in the Senate and then signed into law by President Trump.become law. In the event climate change legislation ultimately passes, the actual economic and operational impact of such legislation on APS depends on a variety of factors, none of which can be fully known until a law is written, and enacted, and the specifics of the resulting program are established. These factors include, without limitation, the terms of the legislation with regard to allowed GHG emissions; the cost to reduce emissions; in the event a cap-and-trade program is established, whether any permitted emissions allowances will be allocated to source operators free of cost or auctioned (and, if so, the cost of those allowances in the marketplace) and whether offsets and other measures to moderate the costs of compliance will be available; and, in the event of a carbon tax, the amount of the tax per pound of carbon dioxide (“CO2”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
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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'sEPA’s 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulationssuch rules would have had been stayed pending judicial review.
Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standards (“NAAQS”) and replacingother rules or matters involving the CPP. Various state governments, industry organizations,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 and public-health public interest groups have filed lawsuitsrules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our fossil-fuel powered plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the D.C. Circuit challenging the legality of EPA’s action, both, in repealing the CPP and issuing the ACE regulations. In addition,plants as well as other costs related to the extent that the ACE regulations go into effect as finalized,early retirement but cannot predict whether it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.would obtain such recovery.
EPA Environmental Regulation
Regional Haze Rules. In 1999, EPA announced regional haze rules to reduce visibility impairment in national parks and wilderness areas. The rules require states (or, for sources located on tribal land, EPA) to determine what pollution control technologies constitute the BART for certain older major stationary sources, including fossil-firedfossil-fuel fired power plants. EPA subsequently issued the Clean Air Visibility Rule, which provides guidelines on how to perform a BART analysis. Final regulations imposing BART requirements have now been imposed on each APS coal-fired power plant. Four Corners was required to install new pollution controls to comply with BART, while similar pollution control installation requirements were not necessary for Cholla.
Cholla. APS believed that EPA’s original 2012In early 2017, EPA approved a final rule establishing controls constituting BART for Cholla, which would require installation of selective catalytic reduction ("SCR") controls, was unsupported and that EPA had no basis for disapprovingcontaining a revision to Arizona’s State Implementation Plan ("SIP"(“SIP”) and promulgating a Federal Implementation Plan ("FIP")for Cholla that was inconsistentimplemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements.In conjunction with the state’s considered BART determinations
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April 2025.PacifiCorp retired Cholla Unit 4 at the mid-2020s. (See "Cholla"end of 2020. See “Cholla” in Note 43 for information regarding future plans for Cholla and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.
Four Corners. Based on EPA’s final standards, APS'sAPS’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. (SeeSee Note 43 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'sPaso’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 Resource Conservation and Recovery Act ("RCRA")RCRA and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed "forced closure"“forced closure” or "closure“closure for cause"cause” of unlined surface impoundments and are the subject of recent regulatory and judicial activities described below.
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, including supporting the passage of new state legislation providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits. The proposal remains pending.
•On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019, to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.
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We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. action on those matters that are still pending.Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows.
APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners.APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22$30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15$16 million.The Navajo Plant currently disposesdisposed of CCR only in a dry landfill storage area.To comply with the CCR rule for the Navajo Plant, APS'sAPS’s share of incremental costs iswas 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 ceasehave ceased operating and initiateinitiated closure by October 31, 2020.April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS initiated an assessmentcompleted the assessments of corrective measures on JanuaryJune 14, 20192019; however, additional investigations and expects such assessmentengineering analyses that will continue through mid- to late-2020. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as tosupport the CCR disposal units at Cholla and Four Corners undergoing corrective action.remedy selection are still underway. In addition, APS will also solicit input from the public and 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.ELGs. On September 18, 2017, EPA finalized a regulation postponing the earliest date on which compliance with the effluent limitation guidelinesELGs for these waste-streams would be required from November 1, 2018, until November 1, 2020. In addition,At this time, APS’s National Pollutant Discharge Elimination System (“NPDES”) discharge permit for Four Corners contains a December 31, 2023,
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compliance deadline for achieving “zero discharge” of bottom ash transport waters. Nonetheless, on November 22, 2019,October 13, 2020, EPA published a proposedfinal rule relaxing thethese “zero discharge” limitations for bottom-ashbottom ash handling water and allowing for approximately 10% of such wastewater to be discharged (on a volumetric, 30-day rolling average basis) subjectunder limited power plant operating scenarios. At this time, APS is pursuing a modification to best-professional judgment effluent limits.the Four Corners NPDES discharge permit in order to implement the most recent ELG rulemaking. We cannot at this time predict the outcome of this rulemaking proceeding. Nonetheless, we expect that compliance with the resulting limitations will be required in connection with National Pollution Discharge Elimination System ("NPDES") discharge permit renewals at Four Corners (see "Four Corners National Pollutant Discharge Elimination System Permit," below, for more details). For the current NPDESmodification proceeding, including any public commenting or permit issued to Four Corners, which is subject to an appeal by various environmental groups, the plant must comply with the existing “zero discharge” effluent limitation guidelines for bottom-ash transport wastewater by December 31, 2023. If those guidelines are changed, it is unclear when Four Corners would need to demonstrate compliance with any updated or revised standards.procedures. The Cholla and the Navajo Plant dofacility 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”)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'sAgency’s final action designating non-attainment areas was not issued until April 30, 2018. At that time, EPA designated the geographic areas containing Yuma and Phoenix, Arizona as in non-attainment with the 2015 70 ppb ozone NAAQS. The vast majority of APS'sAPS’s natural gas-fired EGUs are located in these jurisdictions. Areas of Arizona and the Navajo Nation where the remainder of APS'sAPS’s fossil-fuel fired EGU fleet is located were designated as in attainment. We anticipate that revisions to the SIPs and FIPs implementing required controls to achieve the new 70 ppb standard will be in place between 2023 and 2024. At this time, because proposed SIPs and FIPs implementing the revised ozone NAAQSs have yet to be released, APS is unable to predict what impact the adoption of these standards may have on the Company. APS will continue to monitor these standards as they are implemented within the jurisdictions affecting APS.
Superfund-Related Matters. The Comprehensive Environmental Response Compensation and Liability Act ("CERCLA"(“CERCLA” or "Superfund"“Superfund”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water, or air. Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs"(each a “PRP”). 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"(“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("(“RI/FS"FS”). The RI/FS for OU3. Based upon discussions betweenOU3 was finalized and submitted to EPA at the OU3 working group parties andend of 2022. APS cannot predict the EPA along’s timing with the results of recent technical analyses prepared by the OU3 working grouprespect to supplement the RI/FS,this matter. APS anticipates finalizing the RI/FS in the spring or summer of 2020. We estimateestimates that our costsits cost related to this investigation and study will beis approximately $2$3 million. We anticipateAPS anticipates incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized by EPA, at the present time, expenditures related to this matter cannot be reasonably estimated.
On August 6, 2013, the Roosevelt Irrigation District ("RID"(“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
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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'sAPS’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'sRID’s CERCLA claims concerning both past and future cost recovery. APS'sAPS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the ancillary service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. While this lawsuit remains pending, on September 30, 2022, the U.S. District Court for the District of Arizona granted partial summary judgment to the direct defendants for $20.6 million of the $21 million in CERCLA response costs claimed by the service provider. We are unable to predict the outcome of these matters;any further litigation related to the remaining response costs at issue in this litigation; however, we do not expect the outcome to have a material impact on our financial position, results of operations, or cash flows.
On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform APS that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated.
Manufactured Gas Plant Sites. Certain properties which APS now owns or which were previously owned by it or its corporate predecessors were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, or cash flows.
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"(“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 guidelinesELGs for steam-electric EGUs, 2014 existing-source
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regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018, to withdraw the NPDES permit reissued in June 2018.Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis.The EAB thereafter dismissed the environmental group appeal on February 12, 2019.EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the
Based on the Navajo Reservation and are held under rights of way granted by the federal government, as well as leasesa declaration from the Navajo Nation. See “Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities” above for additional information regarding these plants.
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.
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 companyCompany to secure water for Four Corners in the event of a water shortage
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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 finalfurther ruling affirming this decision by the trial court judge in this matter remains pending.overseeing the adjudication was issued on July 8, 2022. Further proceedings have been initiated to determine the specific hydro-geologic testing protocols for subflow depletion determinations. The determinations made in this final stage of the proceedings may ultimately govern the adjudication of rights for parties, such as APS, that rely on groundwater extraction to support their industrial operations. APS cannot predict the outcome of these proceedings.
Little Colorado River Adjudication. APS has filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’s groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’s claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. Other claimsNo trial or pretrial proceedings have been identified as ready for litigation in motions filed with the court. A trial is scheduled for Juneadjudication of 2020 regarding the contestedAPS’s water right claims. The adjudication court is currently conducting a trial of federal reserved water right claims ofasserted by the Hopi tribeTribe and by the United States as trustee for federal reserve water rights. Similar claims of the
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Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, or cash flows.
Human Capital
The Company seeks to attract the best employees, retain those employees, and 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 retaining its talent and managing its business include the safety of our employees, career development, diversity, equity and inclusion, succession planning, hiring, voluntary turnover, compensation, benefits, employee experience, and engagement.
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 are empowered to speak up when there are better or safer ways of doing business, including stopping work to reassess or improve safety.Safety committees operate in organizations throughout the Company, providing opportunities for employees to positively impact their local safety cultures and performance.
Diversity, Equity, and Inclusion
We believe that belonging matters. When we feel seen, heard, and valued, we can more effectively unite behind the APS Promise. Inclusion at the Company involves taking deliberate action to embrace the unique perspectives of each employee. We recognize that diversity of demographics, backgrounds and cultural perspective is a key driver for our success.Our internal diversity, equity, and inclusion team, supported by our Executive Diversity & Inclusion Council as well as other groups, 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 teams during management review meetings to build awareness and address gaps of workforce diversity.
Our efforts to support and empower employees include a commitment to full inclusion of all our people. We have a robust, multi-year strategy for diversity, equity, and inclusion that focuses on eleven key areas, both internally- and externally-facing. In 2021, APS received recognition as winner of the Inclusive Workplace Award from Diversity Leadership Alliance and Arizona Society of Human Resource Management. The award recognizes APS as an Arizona corporation that leads by example, creating an inclusive environment in which employees can be their genuine, authentic selves, and partners on community outreach efforts and support.
Each year since 2020, we have conducted company-wide executive listening sessions to provide employees with opportunities to be heard on their experiences at the Company. In 2019, we signed the UNITY Pledge in support of full inclusion and equality in employment, housing, and public
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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.
We continue to focus on hiring diverse employees as well as hiring employees from our veteran community. During 2022, 44% of external hires were ethnically or racially diverse, 40% were female and 7% were veterans.Additionally, as of December 31, 2022, 35% of our employees are ethnically or racially diverse, 26% are female, and 15% are veterans. Finally, as of December 31, 2022, 39% of the Company’s officers are female, and 18% are ethnically or racially diverse.
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.
Talent Strategy and Development
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. In 2022, we graduated 138 individuals from our three academies (Leadership Academy, Impact and Influence Academy, and Strategic Leadership Academy).Additionally, our Learning and Development organization was recognized as a top training organization, earnings an APEX Award from Training Magazine.
Talent pipelines help sustain our skilled workforce needs. Pipeline strategies include our apprentice and rotational programs. Additionally, our recruiters target specific colleges and programs of study that we have identified as talent pipelines. In 2022, we hosted 54summer interns with a diversity rate of 63%.
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 well-being, make up our Total Rewards program. It is an important part of the employee experience at the Company and supports
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personal well-being 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.
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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, 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.
BUSINESS OF OTHER SUBSIDIARIES
Bright Canyon Energy
On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. BCE's focusBCE’s strategy is on new growth opportunitiesto develop, own, operate and acquire energy infrastructure in a manner that leverageleverages the Company’s core expertise in the electric energy industry. BCE’s first initiative isAs of December 31, 2022, BCE had total assets of approximately $115.3 million.
In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the eleven11 U.S. states that comprise the Western Electricity Coordinating Council,Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates. As
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On December 20, 2019, BCE acquired minority ownership positions in two wind farms developedunder development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, (collectively, "Tenaska"), the 242 MW Clear Creek wind farm in Missouri (“Clear Creek”) and the 250 MW Nobles 2 wind farm in Minnesota. TheMinnesota (“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 PPAs. BCE indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.
Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022. Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order. On October 7, 2022, the request for rehearing was denied by FERC. FERC has not ruled on the motion for stay. Clear Creek has filed a Petition for Review with the U.S. Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.
Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner. The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.
Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors. These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion, or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC. As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired. Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022. Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $12.8 million relating to this impairment.
BCE has started construction on a microgrid facility in Los Alamitos, California (“Los Alamitos”) featuring 31 MW of solar, 20 MW of battery storage, and 3 MW of backup generators. Supported by a long-term PPA with San Diego Gas and Electric Company, Los Alamitos will supply 20 MW of solar and battery storage capacity to the Southern California grid and provide resilient backup power in the event of a grid emergency to the Army and California National Guard at Joint Forces Training Base Los Alamitos. The Los Alamitos project is expectedscheduled to achieve commercial operation in 2020third-quarter 2023. See Note 6 regarding a credit agreement entered into by BCE to finance capital expenditures and deliver powerrelated costs for this microgrid project.
BCE and Ameresco, Inc. jointly own a special purpose entity that is sponsoring the Kūpono Solar project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a long-term power purchase agreement.20-year PPA with Hawaiian Electric Company, Inc. The Nobles 2Kūpono Solar project is also expected to achieve commercial operationbe completed in 2020 and deliver power under a long-term power purchase agreement. BCE indirectly owns 9.9%2024.
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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 goalDorado is actively seeking to prudently realize the value of its existingthese investments. As of December 31, 2019, El Dorado had total assets of approximately $9 million.In particular, El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.
Pinnacle West, APS and El Dorado are all incorporated in the State of Arizona. BCE and 4CA are incorporated in Delaware. Additional information for each of these companies is provided below:
Principal Executive Office Address | Year of Incorporation | Approximate Number of Employees at December 31, 2019 | Principal Executive Office Address | Year of Incorporation | Approximate Number of Employees at December 31, 2022 | ||||||||||||||||||||||
| Pinnacle West | 400 North Fifth Street Phoenix, AZ 85004 | 1985 | 97 | Pinnacle West | 400 North Fifth Street Phoenix, AZ 85004 | 1985 | 82 | ||||||||||||||||||||
| APS | 400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999 | 1920 | 6,111 | APS | 400 North Fifth Street P.O. Box 53999 Phoenix, AZ 85072-3999 | 1920 | 5,772 | ||||||||||||||||||||
| BCE | 400 East Van Buren Phoenix, AZ 85004 | 2014 | 2 | BCE | 400 East Van Buren Street Phoenix, AZ 85004 | 2014 | 7 | ||||||||||||||||||||
| El Dorado | 400 East Van Buren Phoenix, AZ 85004 | 1983 | — | El Dorado | 400 East Van Buren Street Phoenix, AZ 85004 | 1983 | — | ||||||||||||||||||||
| 4CA | 400 North Fifth Street Phoenix, AZ 85004 | 2016 | — | 4CA | 400 East Van Buren Street Phoenix, AZ 85004 | 2016 | — | ||||||||||||||||||||
| Total | 6,210 | Total | 5,861 | ||||||||||||||||||||||||
The APS number includes employees at jointly-owned generating facilities (approximately 2,4572,059 employees) for which APS serves as the generating facility manager. Approximately 1,3291,162 APS employees are union employees, represented by the International Brotherhood of Electrical Workers ("IBEW"(“IBEW”). In January 2018,March 2020, the Company concluded negotiations with the IBEW and approved a two-yearthree-year extension of the contract set to expire on April 1, 2018.2020. Under the extension, union members received wage increases for 20182020, 2021 and 2019;2022; there were no other changes. The current contract expires on April 1, 2020. In preparation for that expiration, the Company began negotiations with2023, and APS and the IBEW are currently engaged in October 2019 and negotiations are ongoing.to renew the contract.
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WHERE TO FIND MORE INFORMATION
We use our website (www.pinnaclewest.com)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)602-250-3011).
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.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. See Note 10.
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.
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APS’s ability to conduct its business operations and avoid finesnegative operational and penaltiesfinancial impacts depends in part upon compliance with federal, state and local laws, judicial decisions, 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. However, changes
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, 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. In November 2021, the Arizona Court of Appeals issued an opinion that called into question the ACC-approved limitation of liability provision found in the APS Service Schedules. APS sought review of the decision at the Arizona Supreme Court, which was denied; however, the Supreme Court depublished portions of the Court of Appeals’ decision. APS is seeking revised tariff language to mitigate potential adverse impacts on APS’s future, potential litigation exposure which may result from this court decision. We are also unable to predict the impact on our business and operating results from any pending or future regulatory activities of any of these agencies.
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,GHGs, 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,
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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 and in a dry landfill storage area at the Navajo Plant.Corners. To the extent the rule requires the closure or modification of these CCR units, modification or changes to the manner of closure of such 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 standardsNAAQS for nitrogen oxides,ozone, which set new, more stringent standards intendedon emissions of nitrogen oxide, a precursor to ozone, in an effort to 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.
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Potential Financial Risks -— Greenhouse Gas Regulation, the Clean Power Plan and Potential Litigation. In 2015, EPA finalized a rule to limit carbon dioxideCO2 emissions from existing power plants, the Clean Power Plan, or CPP. The implementation of this rule within the jurisdictions where APS operates could resultwould have resulted in a shift in in-state generation from coal to more natural gas and renewable generation. SuchBecause of a substantial change in APS’sview that the federal Clean Air Act did not permit such an expansive use of administrative authority over utility generation portfolio could require additional capital investments and increased operating costs, and thus have a significant financial impact on the Company. EPA took action in October 2017 to repeal these regulations and in July 2019, EPA published final regulations, the ACE Rule, to replace the CPP with a new set of regulations. EPA’s actionresources, in 2019 to repealregulations were issued that repealed the CPP and replacereplaced it with the ACEa far narrower set of regulations is currently subject to pending judicial review infocused solely on coal-fired power plant efficiency improvements. On January 19, 2021, the U.S. Court of Appeals for the DistrictD.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, which endorsed an expansive view of Columbia.the federal Clean Air Act consistent with the CPP, was subsequently reversed by the U.S. Supreme Court on June 30, 2022. While the current administration has expressed its intent to develop new carbon emission regulations governing existing power plants in 2023, such action will be constrained by the U.S. Supreme Court’s decision that the CPP violated the Clean Air Act.
Depending on the final outcome of a pendingfuture 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. Depending on the 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, of ACE and repeal of the CPP, along with related regulatory activity to implement the ACE regulations, 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'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. Large increases in ambient temperatures could require evaluation of certain materials used within its system and may represent a greater challenge. Limitations on water supplies necessary to operate electric generation infrastructure could arise from prolonged drought and shortage declarations associated with key surface water resources. 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 and transmission 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 ourits power plants and transmission facilities 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 and facilities, 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 differencesDifferences 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 43 for a discussion of the Navajo Plant and Cholla retirement and the related risks associated with APS'sAPS’s continued recovery of its remaining investment in the plant.
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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'sACC’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.
In November 2018, the ACC voted to again re-examine retail competition. In addition, proposals to enable or supportthe facilitation of a deregulated retail electric competition may be made from time to time through ballot initiatives, legislative action or other forumsmarket in Arizona. TheOn July 1 and July 2, 2019, ACC has scheduledStaff issued a workshop for February 25-26, 2020 for further considerationreport and discussion ofinitial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changesOn 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 rules results, what impact these rules would have on APS.
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.
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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
APS must also meet certain distributed renewable energy requirements. A portion of APS’s total renewable energy requirement must be met with an increasing percentage of distributed renewable energy resources (generally, small scale renewable technologies located on customers’ properties). The distributed renewable energy requirement is 30% of the applicable RES requirement for 2012 and subsequent years.years (this requirement has been waived by the ACC for 2023). Customer participation in distributed renewable 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'sAPS’s service territory increased 2.0%2.1% for the year ended December 31, 20192022, compared with the prior year.prior-year period. For the three years 2017 through 2019,2022, APS’s retail customer growth averaged 1.8%2.2% per year. We currently project annual customer growth to be 1.5 -1.5% to 2.5% for 20202023 and for 2020the average annual growth to be in the range of 1.5% to 2.5% through 20222025 based on our assessment of improving economic conditionsanticipated steady population growth in Arizona. Arizona during that period.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.6%2.4% for the year ended December 31, 20192022, compared with the prior year. Improving economic conditions andprior-year period. While steady customer growth werewas offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives. initiatives, the main drivers of positive sales for this period were a strong improvement in sales to commercial and industrial customers and the ramp-up of new data center customers.
For the three years 2017 through 2019,2022, annual retail electricity sales were about flat,growth averaged 2.5%, adjusted to exclude the effects of weather variations. WeDue to the expected rapid growth of several large data centers and new large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 1.0 - 2.0%3.5% to 5.5% for 20202023 and increase onthat average annual growth will be in the range of 1.0 - 2.0% during 20204.5% to 6.5% through 2022,2025, including the effects of customer conservation, and energy efficiency, and distributed renewable generation initiatives, but excluding the effects of weather variations and excludingvariations. This projected sales growth range includes the impacts of several new large data centers opening operations in Metro Phoenix. The impact ofand new large data centers could raisemanufacturing facilities, which are expected to contribute to average annual growth in the range of expected sales annual growth rate over the 20203.5% to 2022 period, but demand from these customers remains uncertain at this point. Slower than expected growth of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives could further impact these estimates.
Actual customer and 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, slower ramp-up of and/or fewer data centers and large manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs, and growth in distributed renewable generation, DG,
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and responses to retail price changes. Additionally, recovery ofBased on past experience, a substantial portion of1% variation in 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 estimatedannual residential and small commercial and industrial kWh sales projections which could haveunder normal business conditions can result in increases or decreases in annual net income of approximately $20 million, and a negative impact on1% variation in our financial condition, resultsannual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income 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'sAPS’s results of operations.
Wildfires have the potential to affect the communities that APS serves and APS'sAPS’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 and climate change 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'sAPS’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'sAPS’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'sAPS’s financial condition, results of operations, or cash flows.
The inability to successfully develop, acquire or acquireoperate generation resources to meet future resource needs and load forecasts in accordance with reliability requirements and other new or evolving standards orand 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 abundance of low, stably priced natural gas, together with environmentalregulatory standards, laws, and other concerns surrounding coal-fired generation resources,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 renewables development and energy efficiency measures.measures, in addition to specific competitive resource procurement requirements. The development and operation 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 needs to develop or acquire new generation facilities, potentially modernize existing facilities, and/or contract for additional capacity in order to meet future resource needs and load forecasts. APS’s inability to adequately develop or acquire the necessary generation resourcesdo so 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,
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and constructionoperation 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 any such opposition may have on our ability to develop, construct, and constructoperate 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, adequate supply chain for generation resources, 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 the operation of 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 tosuffer from prolonged drought conditions, which could potentially affect the plants’ water supplies. Climate change is also projected to exacerbate prolongedsuch drought conditions. In addition, Colorado River water supplies for Arizona are subject to a Tier 2a shortage declaration, which substantially limits the quantity of water available for the state. APS’s inability to access sufficient supplies of water, along with that of its customers, 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 particularincluding from both nation state and non-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. Oursystem, our information technology systems, generation (including our Palo Verde nuclear facility), transmission and distribution facilities, and other infrastructure facilities and systems and physical assetsassets. We have been and could be targetsthe target of unauthorized accessattacks, and the aforementioned systems 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
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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 effecteffects 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 couldwould also 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 information 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 willmay 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. The market for cybersecurity insurance is relatively new and coverage availableCoverage for cybersecurity events maycontinues 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 ourAPS’s 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 reactorplant in the United States. In addition, APS is subject to retrospective premium adjustments under its nuclear property insurance policies with Nuclear Electric Insurance Limited (“NEIL”) for approximately $22.3 million if NEIL’s losses in any policy year exceed accumulated funds and if the retrospective premium assessment is declared by NEIL’s Board of Directors. Although we haveAPS has 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'sAPS’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
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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 make APS'sAPS’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 35%30% of employees eligible to retire by the end of 2024.2027. 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.
COVID-19 could negatively affect our business.
COVID-19 is a continually developing situation around the globe that has led to economic disruption and volatility in the financial markets. The spread of COVID-19 and efforts to contain the virus and mitigate its public health effects, 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, impact our ability to hire or retain qualified employees, or cause other unpredictable events, each of which could adversely affect our business, results of operations, cash flows or financial condition.
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 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, new rules or regulations 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.
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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 costs and other postretirement benefit costsexpense and all of the currently estimated nuclear decommissioning costs in our regulated rates. Any inability to fully recover these costs in a timely manner wouldcould have a material negative impact on our financial condition, results of operations, or cash flows.
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 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
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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 (“OTC”) 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 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 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.
General economic conditions could materially affect our business, financial condition, and results of operations.
General economic factors that are beyond the Company’s control impact the Company’s forecasts and actual performance. These factors include interest rates; recession; inflation; stagflation; deflation; supply chain constraints; unemployment trends; sanctions, trade restrictions, military interventions and the threat or possibility of war; terrorism or other global or national unrest; and political or financial instability. In particular, during 2021 and 2022, the United States’ economy has experienced a substantial rise in the inflation rate. There is increased uncertainty as to whether the rise in inflation will continue and for how long. Increases in inflation raise the Company’s costs for commodities, labor, materials and services. Additionally, COVID-19 severely impacted global supply chains, resulting in equipment delays and
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increased costs. A failure to recover the increased costs caused by increased inflation and supply chain constraints through our rates could 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;
•change in our management;
•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, changes to the internal policies of our lenders, 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/or the cost of maintaining these sources.
Changes in economic conditions, monetary policy, fiscal policy, financial regulation, rating agency treatment and/or other factors could result in higher interest rates, which would increase interest expense on our 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.
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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 20192022 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, 20192022 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 (d) | 2 | Gas | Load Following | 1,088 | ||||||||||||||||||||||||||||
| West Phoenix | 5 | Gas | Load Following | 887 | ||||||||||||||||||||||||||||
| Total Combined Cycle | 1,975 | |||||||||||||||||||||||||||||||
| Combustion Turbine: | ||||||||||||||||||||||||||||||||
| Ocotillo (e) | 7 | Gas | Peaking | 620 | ||||||||||||||||||||||||||||
| Saguaro | 3 | Gas | Peaking | 189 | ||||||||||||||||||||||||||||
| Douglas | 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 | 17 | ||||||||||||||||||||||||||||
| Paloma (f) | 1 | Solar | As Available | 17 | ||||||||||||||||||||||||||||
| Chino Valley | 1 | Solar | As Available | 20 | ||||||||||||||||||||||||||||
| Gila Bend (f) | 1 | Solar | As Available | 36 | ||||||||||||||||||||||||||||
| Hyder II (f) | 1 | Solar | As Available | 14 | ||||||||||||||||||||||||||||
| Foothills (f) | 1 | Solar | As Available | 38 | ||||||||||||||||||||||||||||
| Luke AFB | 1 | Solar | As Available | 11 | ||||||||||||||||||||||||||||
| Desert Star (f) | 1 | Solar | As Available | 10 | ||||||||||||||||||||||||||||
| Red Rock | 1 | Solar | As Available | 44 | ||||||||||||||||||||||||||||
| APS Owned Distributed Energy | Solar | As Available | 36 | |||||||||||||||||||||||||||||
| Multiple facilities | Solar | As Available | 4 | |||||||||||||||||||||||||||||
| Total Solar | 264 | |||||||||||||||||||||||||||||||
| Total Capacity | 6,340 | |||||||||||||||||||||||||||||||
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(a)100% unless otherwise noted.
(b)APS’s 29.1% ownership in Palo Verde includes leased interests and is the largest capacity interest of all the participants. 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, SCE, El Paso, Public Service Company of New Mexico, Southern California Public Power Authority, and Los Angeles Department of Water & Power.
| 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 | ||||||||
| Navajo (d) | — | Coal | Base Load | — | ||||||||
| Ocotillo (e) | — | Gas | Peaking | — | ||||||||
| Total Steam | 1,357 | |||||||||||
| Combined Cycle: | ||||||||||||
| Redhawk (f) | 2 | Gas | Load Following | 1,088 | ||||||||
| West Phoenix | 5 | Gas | Load Following | 887 | ||||||||
| Total Combined Cycle | 1,975 | |||||||||||
| Combustion Turbine: | ||||||||||||
| Ocotillo (e) | 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 (g) | 1 | Solar | As Available | 17 | ||||||||
| Hyder I (g) | 1 | Solar | As Available | 16 | ||||||||
| Paloma (g) | 1 | Solar | As Available | 17 | ||||||||
| Chino Valley | 1 | Solar | As Available | 19 | ||||||||
| Gila Bend (g) | 1 | Solar | As Available | 32 | ||||||||
| Hyder II (g) | 1 | Solar | As Available | 14 | ||||||||
| Foothills (g) | 1 | Solar | As Available | 35 | ||||||||
| Luke AFB | 1 | Solar | As Available | 10 | ||||||||
| Desert Star (g) | 1 | Solar | As Available | 10 | ||||||||
| Red Rock | 1 | Solar | As Available | 40 | ||||||||
| APS Owned Distributed Energy | Solar | As Available | 26 | |||||||||
| Multiple facilities | Solar | As Available | 4 | |||||||||
| Total Solar | 240 | |||||||||||
| Total Capacity | 6,316 | |||||||||||
(d)Redhawk generation capacity increased by 104 MW following the Advanced Gas Path upgrade installed on both units.
(e)Ocotillo Steam Units 1 and 2 were retired on January 10, 2019. Units 3 through 7 all went into service on or prior to May 30, 2019, which increased generation capacity by 510 MW. (f)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.
Transmission and Distribution Facilities
Current Facilities. As of January 3, 2023, APS’s transmission facilities consist of approximately 6,1925,828 pole miles of overhead lines and approximately 4985 miles of underground lines, 5,9695,768 miles of which are located in Arizona. APS’s distribution facilities consist of approximately 11,191 11,276 miles of overhead lines and approximately 22,09223,082 miles of underground primary cable (20,021 when excluding abandoned conductor), all of which are located in Arizona. APS also owns and maintains 469 substations, including both transmission and distribution yards. 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, 2019:
2022:
Percent Owned (Weighted-Average) | |||||
| Morgan — Pinnacle Peak System | % | ||||
| Palo Verde — Rudd 500kV System | 50.0 | % | |||
| Round Valley System | 50.0 | % | |||
| ANPP 500kV System | % | ||||
| Navajo Southern System | % | ||||
| Four Corners Switchyards | % | ||||
| Palo Verde — Yuma 500kV System | % | ||||
| Phoenix — Mead System | 17.1 | % | |||
| Palo Verde — Morgan System | % | ||||
| Hassayampa — North Gila System | 80.0 | % | |||
| Cholla 500kV Switchyard | 85.7 | % | |||
| Saguaro 500kV Switchyard | 60.0 | % | |||
| Kyrene | 50.0 | % | |||
| Agua Fria Switchyard | 10.0 | % | |||
Expansion. Each year APS prepares and files with the ACC a ten-year transmission plan.Ten-Year Transmission Plan. In APS’s 2020 plan,2023 Ten-Year Plan, APS projects it will develop 2984 miles of new transmission lines over the next ten10 years. One significant project,Additionally, APS plans to upgrade 55 miles of existing transmission lines over the Palo Verde to Morgan project recently completed all phases and providessame horizon. The 2023 Ten-Year Plan includes a new 25-mile 500kV path that spansline from the Palo Verde hub aroundJojoba substation to the westernRudd substation. The purpose of this 500kV line project is to bring in a new source to the west and northern edgessouthwest parts of the Phoenix metropolitan area and terminates at a bulk substationwhich is experiencing rapid economic development. In addition, this new source will provide customers in the northeast partarea greater access to a diverse mix of Phoenix.resources from around the region. The Palo Verde to Morgan project2023 Ten-Year Plan 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 constructednumerous projects with the capabilitypurpose to employ a 230kV line as a second circuit.
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 co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remainceased operations in operation until December 2019 under the existing plant lease.November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017, that allows for decommissioning activities to begin after the plant ceased operations in November 2019.operations.
APS, 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
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
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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 43 for ACC and FERC-related matters.
See Note 1110 for information regarding environmental matters, and Superfund–related matters.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.any time. The executive officers, their ages at February 21, 2020,27, 2023, current positions and principal occupations for the past five years are as follows:
| Name | Age | Position | Period | |||||||||||||||||
| Jeffrey B. Guldner | Chairman of the Board, | 2019-Present | ||||||||||||||||||
| Chairman of the Board and Chief Executive Officer of APS | ||||||||||||||||||||
| Chairman of the Board, Chief Executive Officer and President of APS | ||||||||||||||||||||
| Chairman of the Board and Chief Executive Officer of APS | 2020-2021 | |||||||||||||||||||
| 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 | |||||||||||||||||||
| Elizabeth A. Blankenship | 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 | |||||||||||||||||||
| Senior Vice President and Chief Financial Officer of Pinnacle West and APS | ||||||||||||||||||||
| Vice President and Treasurer of Pinnacle West and APS | 2020-2022 | |||||||||||||||||||
| Director, Corporate Finance of Consolidated Edison Company of New York, Inc. | 2017-2020 | |||||||||||||||||||
| Donna M. Easterly | 58 | Senior Vice President, Human Resources of APS | 2020-Present | |||||||||||||||||
| Vice President, Human Resources and Ethics of APS | 2017-2020 | |||||||||||||||||||
| Jose L. Esparza | 48 | Senior Vice President, Public Policy of APS | 2022-Present | |||||||||||||||||
| Vice President, Regulatory of APS | 2022 | |||||||||||||||||||
| Officer and Senior Vice President, Customer Engagement and Information Technology of Southwest Gas | 2019-2021 | |||||||||||||||||||
| Vice President, Customer Engagement of Southwest Gas | 2012-2019 | |||||||||||||||||||
| Theodore N. Geisler | 44 | President of APS | 2022-Present | |||||||||||||||||
| Senior Vice President and Chief Financial Officer of Pinnacle West and APS | 2020-2022 | |||||||||||||||||||
| Vice President and Chief Information Officer of APS | 2018-2020 | |||||||||||||||||||
| General Manager, Transmission and Distribution Operations and Maintenance of APS | 2017-2018 | |||||||||||||||||||
| Adam C. Heflin | 59 | |||||||||||||||||||
| Executive Vice President and Chief Nuclear Officer, PVGS, of APS | ||||||||||||||||||||
| Paul J. Mountain | 45 | |||||||||||||||||||
| Vice President and Treasurer of Pinnacle West and APS | ||||||||||||||||||||
| Vice President, Finance and Planning of Pinnacle West and APS | 2020-2022 | |||||||||||||||||||
| General Manager, Finance of Pinnacle West | 2017-2020 | |||||||||||||||||||
| Robert E. Smith | Executive Vice President, General Counsel and Chief Development Officer of Pinnacle West and APS | 2021-Present | ||||||||||||||||||
| Senior Vice President and General Counsel of Pinnacle West and APS | ||||||||||||||||||||
| Jacob Tetlow | 50 | Executive Vice President, Operations of APS | 2021-Present | |||||||||||||||||
| Senior Vice President, Non-Nuclear Operations of APS | 2020-2021 | |||||||||||||||||||
| Vice President, Transmission and | ||||||||||||||||||||
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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 14, 2020,21, 2023, Pinnacle West’s common stock was held of record by approximately 16,94215,182 shareholders.
APS’s common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. The sole holder of APS’s common stock, Pinnacle West, is entitled to dividends when and as declared out of legally available funds. At December 31, 2019,2022, APS did not have any outstanding preferred stock.
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Years Ended December 31,
| Company/Index | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||||
| Pinnacle West Common Stock | $100 | $104 | $113 | $104 | $96 | $109 | |||||||||||||||||
| Edison Electric Institute Index | $100 | $104 | $130 | $129 | $151 | $153 | |||||||||||||||||
| S&P 500 Index | $100 | $96 | $126 | $149 | $192 | $156 | |||||||||||||||||
ITEM 6. [RESERVED]
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| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| (dollars in thousands, except per share amounts) | ||||||||||||||||||||
| OPERATING RESULTS | ||||||||||||||||||||
| Operating revenues | $ | 3,471,209 | $ | 3,691,247 | $ | 3,565,296 | $ | 3,498,682 | $ | 3,495,443 | ||||||||||
| Net income | 557,813 | 530,540 | 507,949 | 461,527 | 456,190 | |||||||||||||||
| Less: Net income attributable to noncontrolling interests | 19,493 | 19,493 | 19,493 | 19,493 | 18,933 | |||||||||||||||
| Net income attributable to common shareholders | $ | 538,320 | $ | 511,047 | $ | 488,456 | $ | 442,034 | $ | 437,257 | ||||||||||
| COMMON STOCK DATA | ||||||||||||||||||||
| Book value per share – year-end | $ | 48.30 | $ | 46.59 | $ | 44.80 | $ | 43.14 | $ | 41.30 | ||||||||||
| Earnings per weighted-average common share outstanding: | ||||||||||||||||||||
| Net income attributable to common shareholders – basic | $ | 4.79 | $ | 4.56 | $ | 4.37 | $ | 3.97 | $ | 3.94 | ||||||||||
| Net income attributable to common shareholders – diluted | $ | 4.77 | $ | 4.54 | $ | 4.35 | $ | 3.95 | $ | 3.92 | ||||||||||
| Dividends declared per share | $ | 3.04 | $ | 2.87 | $ | 2.70 | $ | 2.56 | $ | 2.44 | ||||||||||
| Weighted-average common shares outstanding – basic | 112,442,818 | 112,129,017 | 111,838,922 | 111,408,729 | 111,025,944 | |||||||||||||||
| Weighted-average common shares outstanding – diluted | 112,758,059 | 112,549,722 | 112,366,675 | 112,046,043 | 111,552,130 | |||||||||||||||
| BALANCE SHEET DATA | ||||||||||||||||||||
| Total assets | $ | 18,479,247 | $ | 17,664,202 | $ | 17,019,082 | $ | 16,004,253 | $ | 15,028,258 | ||||||||||
| Liabilities and equity: | ||||||||||||||||||||
| Current liabilities | $ | 2,078,365 | $ | 1,648,964 | $ | 1,197,852 | $ | 1,292,946 | $ | 1,442,317 | ||||||||||
| Long-term debt less current maturities | 4,832,558 | 4,638,232 | 4,789,713 | 4,021,785 | 3,462,391 | |||||||||||||||
| Deferred credits and other | 6,015,136 | 6,028,301 | 5,895,787 | 5,753,610 | 5,404,093 | |||||||||||||||
| Total liabilities | 12,926,059 | 12,315,497 | 11,883,352 | 11,068,341 | 10,308,801 | |||||||||||||||
| Total equity | 5,553,188 | 5,348,705 | 5,135,730 | 4,935,912 | 4,719,457 | |||||||||||||||
| Total liabilities and equity | $ | 18,479,247 | $ | 17,664,202 | $ | 17,019,082 | $ | 16,004,253 | $ | 15,028,258 | ||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| (dollars in thousands) | ||||||||||||||||||||
| OPERATING RESULTS | ||||||||||||||||||||
| Operating revenues | $ | 3,471,209 | $ | 3,688,342 | $ | 3,557,652 | $ | 3,498,090 | $ | 3,494,900 | ||||||||||
| Fuel and purchased power costs | 1,042,237 | 1,094,020 | 992,744 | 1,082,625 | 1,101,298 | |||||||||||||||
| Other operating expenses | 1,741,988 | 1,764,554 | 1,640,369 | 1,556,980 | 1,556,670 | |||||||||||||||
| Operating income | 686,984 | 829,768 | 924,539 | 858,485 | 836,932 | |||||||||||||||
| Other income | 89,854 | 111,015 | 60,482 | 52,081 | 54,225 | |||||||||||||||
| Interest expense — net of allowance for borrowed funds | 201,646 | 206,211 | 192,051 | 183,090 | 176,109 | |||||||||||||||
| Net income before income taxes | 575,192 | 734,572 | 792,970 | 727,476 | 715,048 | |||||||||||||||
| Income taxes | (9,572 | ) | 144,814 | 269,168 | 245,842 | 245,841 | ||||||||||||||
| Net income | 584,764 | 589,758 | 523,802 | 481,634 | 469,207 | |||||||||||||||
| Less: Net income attributable to noncontrolling interests | 19,493 | 19,493 | 19,493 | 19,493 | 18,933 | |||||||||||||||
| Net income attributable to common shareholder | $ | 565,271 | $ | 570,265 | $ | 504,309 | $ | 462,141 | $ | 450,274 | ||||||||||
| BALANCE SHEET DATA | ||||||||||||||||||||
| Total assets | $ | 18,370,723 | $ | 17,565,323 | $ | 16,893,751 | $ | 15,931,175 | $ | 14,982,182 | ||||||||||
| Liabilities and equity: | ||||||||||||||||||||
| Total equity | $ | 5,998,803 | $ | 5,786,797 | $ | 5,385,869 | $ | 5,037,970 | $ | 4,814,794 | ||||||||||
| Long-term debt less current maturities | 4,833,133 | 4,189,436 | 4,491,292 | 4,021,785 | 3,337,391 | |||||||||||||||
| Total capitalization | 10,831,936 | 9,976,233 | 9,877,161 | 9,059,755 | 8,152,185 | |||||||||||||||
| Current liabilities | 1,492,029 | 1,576,097 | 1,098,274 | 1,094,037 | 1,424,708 | |||||||||||||||
| Deferred credits and other | 6,046,758 | 6,012,993 | 5,918,316 | 5,777,383 | 5,405,289 | |||||||||||||||
| Total liabilities and equity | $ | 18,370,723 | $ | 17,565,323 | $ | 16,893,751 | $ | 15,931,175 | $ | 14,982,182 | ||||||||||
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. This discussion provides a comparison of the 20192022 results with 20182021 results. A comparison of the 20182021 results with 20172020 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, 2018.2021. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.
OVERVIEW
Business Overview
Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $18$23 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.
Inflation
Overall inflation has grown by 9.5% in Phoenix in 2022, compared to 6.5% nationally; however, APS’s work with national and international companies has helped to partially reduce local cost escalation impacts on APS. The impacts from inflation have varied across separate categories of APS’s spending. Pricing increases across major categories have ranged from 8% to 10% for vendor services and up to 15% to 60% for equipment in 2022. APS has seen specific inflationary impacts in individual spend categories, as well as general inflationary pricing impacts on a broader set of spend categories. Some of the highest increases in 2022 as compared to 2021 have been in chemical costs and contract services.
Even prior to these increases, APS has focused on its customer affordability initiative, which has enabled APS to mitigate inflationary pressure. This initiative includes identifying efficiency opportunities through APS’s LEAN Sigma approach as well as other corporate decisions. For example, APS maintains its inventory to take advantage of lower pricing, when available, and to minimize supply chain delays that can increase the pricing due to expediting fees. Additionally, APS has proactively entered into long-term contracts to hedge against price volatility, which has allowed it to mitigate several procurement spend areas such as transformers.
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Inflation Reduction Act of 2022
On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”). The IRA significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage. Key provisions that are relevant to the Company’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a Production Tax Credit (“PTC”) in lieu of the Investment Tax Credit (“ITC”) beginning in 2022; (ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023; and (iii) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032. The Internal Revenue Service and U.S. Treasury are expected to issue regulations and other guidance which will provide additional details and clarifications regarding how the Company may be able to claim each of these credits.
In addition, the IRA contains several provisions which could create additional tax liabilities for corporations, including a 15% corporate alternative minimum tax for corporations with net profits in excess of $1 billion and a 1% excise tax on stock buybacks. We currently do not believe the Company will be subject to any material tax liabilities as a result of these legislative provisions.
COVID-19
COVID-19 continues to be an evolving situation. Essential planned work and capital investments continued during the pandemic with priority given to support fire mitigation and summer storm efforts, as well as heat-related outages. Raw material shortages, rising inflation, COVID-19 related work force disruptions and natural disasters continue to place increased pressure on the global supply chain. APS is experiencing some delays in finished materials and tight labor markets. To date, APS has not experienced labor or material supply chain shortages that have significantly impacted its ability to serve its customers’ needs. However, shortages are causing minor delays and shifting of work projects based on material availability. If APS continues to experience delays in materials, it could experience an increase in purchased power costs for summer generation needs. Such increased purchased power costs would be expected to be recoverable through the PSA. See Note 3 for additional information on the PSA. APS has measures in place to continually monitor and evaluate resource needs and supply chain adequacy but cannot predict whether there will be material supply chain shortages in the future.
While the total expected impact of COVID-19 on future sales is currently unknown, APS experienced higher electric residential sales and lower electric commercial and industrial sales from the outset of the pandemic through April 2021.Beginning in May 2021, electric sales from commercial and industrial customers increased to levels in line with pre-COVID-19 sales but residential sales continued to be higher than pre-COVID-19 sales. Based on past experience, a 1% variation in our annual residential and small commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $5 million.
The Coronavirus Aid, Relief, and Economic Security (“CARES”) Act allowed 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, which was approximately $18 million. As of December 31, 2022, we have paid this cash deferral in full.
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Due to COVID-19, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020 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 voluntarily began waiving late payment fees of its customers on March 13, 2020. Effective February 1, 2023, late payment fees for residential customers were reinstated, and late payment fees for commercial and industrial customers were reinstated effective May 1, 2022. See Note 3 for additional information regarding the Summer Disconnection Moratorium.
More detailed discussion of the impacts and future uncertainties related to COVID‑19 can be found throughout this Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Combined Notes to Pinnacle West’s and APS’s financial statements that appear in Part II, Item 8 of this report and “Risk Factors” in Part I, Item 1A of this report.
Strategic Overview
Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona by serving our customers with a clean, affordable, reliable, and customer-focused plan.
Clean Energy Commitment
We are committed to doing our part to make the future clean and carbon-free. As Arizona stewards, we do what is right for the people and prosperity of Arizona.Our vision is to create a sustainable energy future for APSArizona through providing clean, affordable, and Arizona presents an opportunity to engagereliable energy.We can accomplish our visions through collaboration with customers, to achievecommunities, employees, policymakers, shareholders, and other stakeholders. Our clean energy goals. Guided bygoal is based on sound science our approach is intended to encourage market-based and innovative solutions to drive towards a low-carbon economy. We believe clean energy can power a robust economy.supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.
•An aspirationala 2050 goal to provide 100% clean, carbon-free electricity;
•Aa commitment to end APS’s use of coal-fired generation by 2031.
2050 Aspirational Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and depends on improved and new technologies.
2030 Goal: 65% Clean Electricity.Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. ThoseBy building on those plans, are intended to allow usAPS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS'sAPS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix which includes all carbon-free resources like nuclear, renewables, and demand-side management. “Renewable” energy includes generation sources such as solar, wind, and biomass, and is measured in accordance with the ACC’s Renewable Energy
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Standard as a percentage of retail sales. This target will 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'sAPS’s Use of Coal-Fired Generation. The commitment to end APS'sAPS’s use of coal-fired generation by 2031 will require APS to cease buyinguse of coal-generation fromat Four Corners.APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of 28%33% 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 provided 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 energy projects. Our proposed CCT plan supported the Navajo Nation, where Four Corners is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which was impacted by closure of the Navajo Plant. On November 2, 2021, the ACC approved an amended 2019 Rate Case ROO that will require (i) equal payments over a three-year period that total $10 million to the Navajo Nation, (ii) a $1 million one-time payment to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (iii) a $500,000 one-time payment to the Navajo County communities within 60 days of the 2019 Rate Case decision, (iv) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (v) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. The payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant. All ordered payments and expenditures would be recoverable through rates. See Note 3 for a discussion of the CCT plan.
Consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $3.33 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $0.5 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County Communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.
On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities. APS and other interested parties filed comments on the report. On October 21, 2022, ACC Staff filed a revised report and proposed order. The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers. On December 8, 2022, the ACC voted against ACC Staff’s proposed order. APS cannot predict if the ACC will take any further action on this matter.
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In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners beginning in fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership. Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring. The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages. APS anticipates that it will elect not to begin seasonal operation in November 2023, unless market conditions change.
Renewables. APS’s IRP (see Note 3 for additional information) establishes the path to meeting our clean energy commitment and maintaining reliable electric service for our customers. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Our IRP rapidly adds clean energy and storage resources while maintaining reliable and affordable service. Its near-term actions includeare focused on clean energy and positive customer outcomes and includes: (a) competitive solicitations to procure clean energy resources such as solar, wind, energy storage, demand response and DSM resources, including energy efficiency resources that enable renewable additions andall of which lead to a cleaner grid.grid; and (b) strategic, short-term wholesale market purchases from a combination of existing merchant natural gas units, neighboring utility systems, and wholesale market participants that ensure operational reliability.
APS uses competitive “All-Source” RFPs to pursue market resources that meet its system needs and offer the best value for customers. APS selects projects based on cost and commercial viability, taking into consideration timing and likelihood of successful contracting and development. Under current market conditions, APS must aggressively contract for resources that can withstand supply chain and other geopolitical pressures. Available projects are guided by IRP timelines and quantities and APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the RFP process. 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.
In September 2019, APS issued an RFP that requested up to 250 MW of wind resources to be in service as soon as possible, but no later than 2022. As a result of this RFP, APS executed a 200 MW PPA for a wind resource that went into service in January 2022. In December 2020, APS issued two additional RFPs: (i) a battery storage RFP for projects to be located at two AZ Sun sites; and (ii) an all source RFP that solicited resources to meet our clean energy needs and capacity to maintain system reliability, and that was later amended to include a request for 150 MW of solar resources to be developed on APS property and owned by APS. As a result of the December 2020 RFPs, APS executed two solar plus storage PPAs totaling 275 combined MW, a PPA for a 238 MW wind resource, two energy storage PPAs for a combined 300 MW, extended an existing natural gas tolling agreement and also executed an engineering,
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procurement, and construction contract in November 2021 for a 150 MW solar resource to be owned by APS and in service in early 2023.
In May 2022, APS issued an RFP to address resource needs for 2025 and beyond. The 2022 RFP solicits competitive proposals for approximately 1,000 MW to 1,500 MW of resources, including up to 600 MW to 800 MW of renewable resources to meet the needs of 2025 and 2026 while considering resources that can be online as late as 2027. The 2022 RFP stopped accepting bids on July 15, 2022, and APS sent notifications to shortlisted bidders on September 23, 2022. As a result of the 2022 RFP, and as of December 31, 2022, APS has signed a PPA for 300 MW of solar plus energy storage resources and a PPA for 216 MW of wind resources. Once it secures those important resources and closes out the 2022 RFP, APS intends to issue its next RFP to address future resource needs.
Energy Storage. APS deploys a number of advanced technologies on its system, including energy storage. Energy storage provides capacity, improves power quality, can be utilized for system regulation and, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage also aids in integrating renewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to meet customer reliability requirements, increase renewable utilization, and further our understanding of how storage works with other advanced technologies and the grid.
In 2018, APS issued RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites.Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site.These battery storage facilities are currently expected to be in service during the first quarter of 2023.On August 2, 2021, APS executed a contract for an additional 60 MW of utility-owned energy storage to be located on APS’s AZ Sun sites.This contract, with a 2023 in-service date, will complete the addition of storage on current APS-owned utility-scale solar facilities.
Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW.These PPAs were subject to ACC approval in order to allow for cost recovery through the PSA.APS received the requested ACC approval on January 12, 2021, and service under the agreements is expected to begin in 2023.
As a result of its December 2020 RFPs, APS executed four 20-year PPAs for resources that include energy storage:(a) two PPAs for standalone energy storage resources totaling 300 MW; and (b) two PPAs for solar plus energy storage resources totaling 275 MW. The PPAs are also subject to ACC approval to enable cost recovery through the PSA. APS received the requested ACC approval for three out of four of the projects on December 16, 2021 and on April 13, 2022 for the remaining project. Service under the agreements is expected to begin in 2023 and 2024.
Following the 2022 RFP, as of January 2023, APS has executed a 20-year PPA for solar plus storage resources totaling 300 MW. The PPA is subject to ACC approval to enable cost recovery through the PSA, which was requested in December 2022 and approved in February 2023. Service under this agreement is expected to begin in 2025.
APS currently plans to install more than 1,200 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.
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The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2021. Agreements for the development and completion of future resources are subject to various conditions.
Net Capacity in Operation (MW) | Net Capacity Planned / Under Development (MW) | ||||||||||||||||
| APS Owned Energy Storage | — | 201 | |||||||||||||||
| PPAs Energy Storage | — | 1,025 | |||||||||||||||
| Residential Energy Storage | 19(a) | 7 | |||||||||||||||
| Total Energy Storage Portfolio | 19 | 1,233 | |||||||||||||||
(a) This includes 18.5 MW of APS customer-owned batteries and 0.2 MW of APS-owned residential batteries.
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. Palo Verde is not just the cornerstone of our current clean energy mix,mix; it also is a significant provider of clean energy to the southwest United States. The plant’splant is a critical asset to the Southwest, generating more than 32 million MWh annually – enough power for roughly 3.4 million households, or approximately 8.5 million people. Its 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
Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and eliminating waste. Through theachieving internal efficiencies. APS continues to drive this initiative by identifying opportunities to streamline its business processes to assist in mitigating cost increases, increasing employee retention, and existing cost management practices, APS identified $20 million in possible cost savings for 2020.improving customer satisfaction.
Participation in the EIM continues to be an effectivea tool for creating savings for ourAPS’s customers from the real-time, voluntary market. OverAPS continues to expect that its participation in EIM will lower its fuel and purchased-power costs, improve situational awareness for system operations in the past three years,Western Interconnection power grid, and improve integration of APS’s renewable resources. APS continues to evaluate opportunities that benefit our customers and is exploring opportunities to move to a day-ahead market with the EIM has delivered approximately $140 million in gross benefits toexpectation of reliably achieving incrementally greater cost savings and using the region’s increasing renewable resources more efficiently. As part of that effort, APS customers.is exploring several options. APS is in discussions with the current EIM operator, the CAISO, the Western Resource Adequacy Program, the Western Markets Exploratory Group, and the Southwest Power Pool. Each of these explorations also involve other EIM participants aboutentities and are being undertaken to evaluate the feasibility and cost/benefit of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.
market.
Reliable
While our energy mix evolves, the obligation to deliver reliable service to our customers remains. Excluding voluntary outages and proactive fire mitigation efforts, APS finished 2019 with its best score for frequencyis managing through significant growth in the Phoenix metropolitan area while experiencing supply chain issues similar to other industries.
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Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth, and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data. (See "Liquidity and Capital Resources - Capital Expenditures" below for additional details on capital expenditures.)
Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, continue ongoing system upgrades, 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 plantPower 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.
APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, customer partnerships to manage peak demand, fire mitigation, and operational preparedness. Seasonal readiness procedures at APS also include walkdowns to ensure good material conditions and critical control system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.
Customer-Focused
Recognizing that creating customer value is inextricably linked to increasing shareholder value, APS’s focus remains on its customers and the communities it easierserves. Accordingly, it is APS’s goal to achieve an industry-leading, best-in-class customer experience, while demonstrating compassion and advocacy for its customers. This multi-year objective includes incrementally improving APS’s J.D. Power (“JDP”) overall customer satisfaction ratings from the fourth quartile to the first quartile of its peer set comprised of large investor-owned utilities. APS made progress on that front in 2022.
As previously disclosed, APS’s JDP Residential rankings for overall customer satisfaction rating improved in 2020 and 2021. That improvement trend continued with the JDP Residential 2022 year-end results. Compared to 2021, APS made quartile gains in every single driver of residential customer satisfaction, firmly lifting APS into the second quartile nationally. Consequently, overall residential satisfaction is now above industry benchmarks when compared to APS’s large investor-owned peers. APS’s strongest performing drivers for the year were Customer Care (phone and digital), Power Quality and Reliability, Corporate Citizenship, and Billing & Payment. Additionally, the JDP Business 2022 full-year results place APS in the top – or first – quartile of utilities nationally for business customers. As a
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result, APS is among the most improved utilities in the nation for both residential and business customer satisfaction.
In mid-2021, APS initiated an organization-wide customer experience strategy council designed to further drive a customer-oriented culture and improve customer satisfaction. Through this and other on-going customer-centric initiatives, APS has embraced increased empathy training for care center associates and adopted more flexible payment arrangements for customers. Numerous customer web-based enhancements also were implemented, including streamlined navigation and Spanish language transaction capabilities on aps.com; an enhanced online power outage center; and enrollment of more than 1 million customers for outage email and text notifications. Additionally, APS launched a broad-reaching multi-channel communications campaign focused on messages that matter most to APS’s customers – reliability, energy-efficiency, financial assistance, the environment, and programs that enable customers to do business with them. In 2019, APS launched its redesigned aps.com website and mobile app, giving customers upgraded access todesign their own personalized energy usage data and billing information. APS's Customer Care team is using speech analytics to enrich advisors’ interactions with customers over the telephone, and customers can also communicate with APS through an online chat.experience.
APS expanded financialoffers assistance programs that provide discounts to qualified limited-income customers, as well as programs to help for itscustomers stay current on their bills. And, to ensure our most vulnerable customers are connected to these programs, we train and work with more than 100 community action agencies. APS’s Energy Support program gives qualified limited-income customers a 25% discount on their bill each month. Additionally, qualified customers experiencing an unplanned major expense or an unexpected reduction in 2019, allocating $2.75income can receive up to $800 a year to cover current or past due APS bills through the Crisis Bill Assistance program. Making customers aware of the assistance programs and resources available to them is a top priority for APS, and we have significantly increased the level of marketing and customer outreach through various campaigns and communication channels. As of December 31, 2022, approximately 60,000 customers received an aggregate of about $29.6 million in crisis bill assistance and increasingfrom various sources, with the individual benefit for qualifying customerslargest amount coming from $400 to $800 per year. The APS Solar Communities program has allowed more than 600 limited- and moderate-income customers to support clean energy and save money by hosting APS-owned solar systemsthe Arizona Department of Economic Security’s Emergency Rental Assistance Program. This assistance is on their residences in exchange for a monthly bill credit.
Developing Clean Energy Technologies
Electric Vehicles
APS plans to makeis making electric vehicle charging more accessible for its customers and helphelping Arizona businesses, schools and governments electrify their fleets. In 2019,2021, APS implementedcontinued its expansion of its Take Charge AZ Pilot Program. As of December 31, 2022, APS had installed 668 Level 2 (“L2”) charging ports at customer locations, with more stations expected to be added through 2023. The program provides
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charging equipment, installation, and maintenance to business customers, government agencies, non-profits, and multifamily housing communities. RatesIn addition to the L2 charging stations, APS has deployed DC fast charging (“DCFC”) stations that are designedowned and operated by APS at five locations in Arizona. The first location opened for public use in March 2022 in Show Low, Arizona. The other four projects in Sedona, Prescott, Globe, and Payson were energized by the end of 2022. Each location features 2-150 kilowatt and 2-350 kilowatt DCFC ports. Charging at these stations will be accessible through the Electrify America charging network. APS has a goal to encouragereach 450,000 light-duty electric vehicles in its service territory by 2030.
Additionally, as part of APS’s DSM Plan, APS has launched an Electric Vehicle Charging Demand Management Pilot Program to proactively address the growing electric demand from electric vehicle charging overnightas electric vehicles become more widely adopted. This program includes the APS SmartCharge data gathering program, a $250 residential electric vehicle smart charger rebate for qualifying electric vehicle chargers, Fleet Advisory Services, and during daytime off-peak hours when solar energya $100 rebate to home builders for new homes to be built EV ready with 240V charging station garage outlets. APS filed its 2023 DSM Plan on November 30, 2022, which proposes two new programs, an expanded residential EV Managed Charging Program and a Commercial Make-Ready Program. The Commercial Make-Ready Program is abundant.
The ACC ordered certain public service corporations, including APS, to develop a long-term, comprehensive statewide transportation electrification plan (“TE Plan”) for Arizona. The statewide 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 actively participated in the development of that plan, which was approved by the ACC in December 2021. In the decision, the ACC also ordered APS and another large Arizona electric public service corporation to each develop and submit for ACC approval their own TE Plans and corresponding budget for 2023. Accordingly, APS met its compliance obligation and filed both a 2023 TE Plan on June 1, 2022 and a supplemental TE Plan on November 30, 2022. APS will file its required TE progress reports on March 15 and September 15, 2023, along with a 2024 TE Plan later this year.
Hydrogen Production
APS, in partnership with Idaho National Laboratory (“INL”), Energy Harbor Corporation (“Energy Harbor”), and two other utilities, has beenXcel Energy Incorporated (“Xcel”), was chosen by the DOE'sDOE’s Office of Nuclear Energy to participate in a series of hydrogen production projectprojects with the goal to improve the long-term economic competitiveness of the nuclear power industry. The project, planned formulti-phase projects began in 2020 through 2022, will lookwith a series of small-scale hydrogen production demonstration projects led by Energy Harbor and Xcel, as well as a technical and economic assessment performed by INL of using electricity generated at how hydrogenPalo Verde to produce hydrogen.
Based on the experience from Palo Verde may be usedVerde’s utility partners’ small scale demonstration projects and from the Palo Verde-specific technical and economic assessment performed by INL, in April 2021, PNW Hydrogen LLC (“PNW Hydrogen”), a newly formed subsidiary of Pinnacle West, applied for DOE funding for a larger scale hydrogen production demonstration project using electricity sourced from Palo Verde. On October 7, 2021, PNW Hydrogen was notified that DOE’s Office of Energy Efficiency & Renewable Energy and Office of Nuclear Energy had selected PNW Hydrogen’s application for an award of $20 million in federal funding to support the hydrogen production demonstration project, subject to
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negotiation and execution of a definitive Cooperative Agreement funding instrument between PNW Hydrogen and DOE. PNW Hydrogen continues to work through negotiations with DOE, while also investigating how best to coordinate its efforts with the Southwest Clean Hydrogen Innovation Network (“SHINe”) regional hub on development opportunities.
SHINe Regional Hub.The Infrastructure Investment and Jobs Act (“IIJA”), also known as energy storagethe Bipartisan Infrastructure Bill, was signed into law on November 15, 2021. Among other things, the IIJA included money for use in reverse-operable electrolysis or peaking gas turbines during timesregional clean hydrogen hubs, and on February 15, 2022, the Department of Energy DOE announced a Request for Information to collect feedback from stakeholders to inform the implementation and design of the day when photovoltaic solarregional hubs.
On May 12, 2022, APS, along with three other Arizona energy sources are
On September 22, 2022, the DOE opened applications for the up to $7 billion program to create six to ten regional clean hydrogen hubs across the country. Concept papers for each regional hub were due by November 7, 2022, and hydrogen generation missions in solar-dominated electricity markets, and demonstrate how hydrogen may be used as energy storageAzCaNE submitted a concept paper for the SHINe regional hub. On December 27, 2022, the SHINe regional hub was one of thirty-three regional hubs encouraged to provide electricity during operating periods when solar is not available.
Carbon Capture
Carbon capture technologies can isolate atmospheric CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. At the same time, these generators are dispatchable: they can supply energy quickly as needed for reliability. Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. There are a number of demonstration projects that show promise but are still being tested in real-world conditions. APS will continue to monitor this emerging technology.
Environmental, Social, and Governance (“ESG”) Practices
Pinnacle West has been integrating ESG practices into its core work for almost 30 years. As a business strategy, we seek solutions that provide “shared value,” meaning solutions that address societal and environmental challenges in a way that also delivers business value. Our commitment extends beyond implementing sustainability practices; we are dedicated to working with our stakeholders to identify and address the sustainability issues that we are uniquely positioned to impact through our business. In 2020, in support of our clean energy commitment and the growing focus on ESG within our organization, we increased our efforts by dedicating a new Sustainability Department at Pinnacle West to integrating ESG best practices into the everyday work of the Company.
As a first step, the Company engaged the Electric Power Research Institute (“EPRI”) and leveraged input from employees, large customers, limited-income advocates, economic development groups, environmental non-governmental organizations, leading sustainability academics and other stakeholders to
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identify and assess the sustainability issues that matter most. In total, 23 Priority Sustainability Issues (“PSIs”) were identified and prioritized. The most critical category, Integral Shared Value, includes four issues deemed most important and most able to be impacted by our actions: clean energy, customer experience, energy access and reliability and safety and health. These Integral PSIs provide the foundation for informing our strategic direction, creating a framework for incorporating best practices and driving enterprise-wide alignment and accountability. In 2021, the Company engaged EPRI for the second phase of this work, focused on benchmarking best practices within these four Integral Shared Value PSIs. We utilized the benchmarking information to identify opportunities for further improvement in our ESG performance.
In 2021, the Company established a Social Issues Committee Framework. The goal of the framework is to provide a process for considering emergent social issues, and for determining whether or how best to engage. The committee’s responsibility is to determine, using a set of principles grounded in the APS Promise and the PSIs, whether engagement on specific emergent social issues is appropriate and, if so, how best to engage.
The Company also finalized an ESG Strategic Framework to guide our work. The framework is based upon three foundational pillars: ESG Policy Advocacy (we advocate for policy that supports our clean energy goals); Driving Performance (improving our ESG performance in the most important areas, including our PSIs); and effectively communicating and amplifying our ESG story to our various stakeholders, including investors, customers, employees and beyond. Throughout 2022, the ESG Strategic Framework has guided our ESG activities allowing the Sustainability Department to prioritize projects and collaborate with our teams in the Company. Also in 2022, the Company developed an ESG Narrative, aligned to the APS Promise, to guide the Company’s communications strategy internally and externally to customers to effectively share APS’s sustainability story.
Regulatory Overview
APS filed an application with the ACC foron October 28, 2022 (the “2022 Rate Case”) seeking an annual increase in annual retail base rates on the date rates become effective (“Day 1”) of $69a net $460 million. This amount includesDay 1 net impact represents a total base revenue deficiency of $772 million offset by proposed adjustor transfers of cost recovery of the deferralto annual retail rates 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 revenue increase in APS's application is $184 million.adjustor mechanism modifications. The average annual customer bill impact of APS’s request on Day 1 is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%)13.6%.
The principal provisions of APS'sAPS’s application are:
•a test year comprised of twelve12 months ended June 30, 2019,2022, adjusted as described below;
•an original cost rate base of $8.87$10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:
| Capital Structure | Cost of Capital | Capital Structure | Cost of Capital | |||||||||||||||||||||||
| Long-term debt | Long-term debt | 45.3 | % | 4.10 | % | Long-term debt | 48.07 | % | 3.85 | % | ||||||||||||||||
| Common stock equity | Common stock equity | 54.7 | % | 10.15 | % | Common stock equity | 51.93 | % | 10.25 | % | ||||||||||||||||
| Weighted-average cost of capital | Weighted-average cost of capital | 7.41 | % | Weighted-average cost of capital | 7.17 | % | ||||||||||||||||||||
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•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•modification of its adjustment mechanisms including:
▪eliminate the Environmental Improvement Surcharge and collect costs through base rates,
▪eliminate the Lost Fixed Cost Recovery mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),
▪maintain as inactive the Tax Expense Adjustor Mechanism,
▪maintain the Transmission Cost Adjustment mechanism,
▪modify the performance incentive in the DSMAC, and
▪modify the Renewable Energy Adjustment Charge to include recovery of capital carrying costs of APS owned renewable and storage resources;
•changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need; and
•twelve months of post-test year plant to reflect used and useful projects that will be placed into service prior to July 1, 2023.
APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request.
2019 Retail Rate Case
On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) seeking an increase or decrease in its Arizona property taxes attributableannual retail base rates. On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. See Note 3 for information regarding the 2019 Rate Case ROO.
On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to tax rate changes after the date2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, (ii) the rate application is adjudicated;
recovery of the deferral and rate base effects of the construction and operating costs and construction of the Ocotillo modernizationFour Corners SCR project, with the exception of $215.5 million (see Note 4 discussion“Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2017 Settlement Agreement); and
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Corners SCR plant investments and deferrals (see Note 4“Four Corners SCR Cost Recovery” below for details relatedadditional information) and the 20 basis point penalty reduction to the resulting regulatory asset).
Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers. APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline. APS cannot predict if the ACC will take any further action on this matter.
Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $3.33 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $0.5 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County Communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.
See Note 43 for information regarding additional regulatory matters.
Four Corners SCR Cost Recovery
As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2022. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See Note 3 for additional information regarding the Four Corners SCR cost recovery.
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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 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 focusBCE’s strategy is on new growth opportunitiesto develop, own, operate and acquire energy infrastructure in a manner that leverageleverages the Company’s core expertise in the electric energy industry. BCE’s first initiative isAs of December 31, 2022, BCE had total assets of approximately $115.3 million.
In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the eleven11 U.S. states that comprise the Western Electricity Coordinating Council,Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.
On December 20, 2019, BCE acquired minority ownership positions in two wind farms developedunder development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek wind farm in Missouri and the 250 MW Nobles 2 wind farm in Minnesota. Thefarms. 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 PPAs. BCE indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.
Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022. Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order. On October 7, 2022, the request for rehearing was denied by FERC. FERC has not ruled on the motion for stay. Clear Creek has filed a Petition for Review with the U.S. Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.
Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner. The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.
Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors. These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion, or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC. As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired. Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022.
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Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $12.8 million relating to this impairment.
BCE has started construction on a microgrid facility in Los Alamitos, California featuring 31 MW of solar, 20 MW of battery storage, and 3 MW of backup generators. Supported by a long-term power purchase agreement with San Diego Gas and Electric Company, Los Alamitos will supply 20 MW of solar and battery storage capacity to the Southern California grid and provide resilient backup power in the event of a grid emergency to the Army and California National Guard at Joint Forces Training Base Los Alamitos. The Los Alamitos project is expectedscheduled to achieve commercial operation in 2020third-quarter 2023. See Note 6 regarding a credit agreement entered into by BCE to finance capital expenditures and deliver powerrelated costs for this microgrid project.
BCE and Ameresco, Inc. jointly own a special purpose entity that is sponsoring the Kūpono Solar project. This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a long-term20-year power purchase agreement.agreement with Hawaiian Electric Company, Inc. The Nobles 2Kūpono Solar project is also expected to achieve commercial operationbe completed in 2020 and deliver power under a long-term power purchase agreement. BCE indirectly owns 9.9% of the Clear Creek project and 5.1% of the Nobles 2 project.2024.
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. In particular, El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.As of December 31, 2022, El Dorado has contributed approximately $12.5 million to the Energy Impact Partners fund.Additionally, El Dorado committed to a $25 million investment in AZ-VC (formerly the invisionAZ Fund), which is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately held early stage and emerging growth technology companies and businesses primarily based in the State of Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in the State of Arizona. As of December 31, 2022, El Dorado has contributed approximately $2.6 million to AZ-VC. The remainder of the investment will be contributed by El Dorado as investments are selected by AZ-VC.
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 20172020 through 2019,2022, retail electric revenues comprised approximately 95%92% 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.
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Actual and Projected Customer and Sales Growth.��Retail customers in APS’s service territory increased 2.0%2.1% for the year ended December 31, 20192022, compared with the prior year.prior-year period. For the three years 2017 through 2019,2022, APS’s customer growth averaged 1.8%2.2% per year. We currently project annual customer growth to be 1.5 -1.5% to 2.5% for 20202023 and for 2020the average annual growth to be in the range of 1.5% to 2.5% through 20222025 based on our assessment ofanticipated steady economicpopulation growth in Arizona.Arizona during that period.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.6%2.4% for the year ended December 31, 20192022, compared with the prior year. Steady economic growth andprior-year period. While steady customer growth werewas offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives. initiatives, the main drivers of positive sales for this period were a strong improvement in sales to commercial and industrial customers and the ramp-up of new data center customers.
For the three years 2017 through 2019,2022, annual retail electricity sales were about flat,growth averaged 2.5%, adjusted to exclude the effects of weather variations. WeDue to the expected rapid growth of several large data centers and new large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 1.0 - 2.0%3.5% to 5.5% for 20202023 and increase onthat average annual growth will be in the range of 1.0 - 2.0% during 20204.5% to 6.5% through 2022,2025, including the effects of customer conservation, and energy efficiency, and distributed renewable generation initiatives, but excluding the effects of weather variations and excludingvariations. This projected sales growth range includes the impacts of several new large data centers opening operations in Metro Phoenix. The impact ofand new large data centers could raisemanufacturing facilities, which are expected to contribute to average annual growth in the range of expected sales annual growth rate over the 20203.5% to 2022 period, but demand from these customers remains uncertain at this point. Slower than expected growth of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives could further impact these estimates.5.5% through 2025.
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, slower ramp-up of and/or fewer data centers and large manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs, and growth in distributed generation,DG, and responses to retail price changes. Based on past experience, a reasonable range of1% variation in our annual residential and small commercial and industrial kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to approximately $15$20 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $5 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, ourOur experience indicates that the more typical variations from normal weather can result in increases orand decreases in annual net income of up to $15 million.million; however, extreme weather variations have resulted in larger annual variations in net income.
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 managementDSM related expenses (which are offset by the same amount of operating revenues) and other factors.
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Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See "Liquidity“Liquidity and Capital Resources"Resources” below for information regarding the planned additions to our facilities and income tax impacts related to bonus depreciation.facilities.
Pension and Other Postretirement Non-Service Credits, Net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.9%10.2% of the assessed value for 2019, 11.0%2022, 10.7% for 20182021 and 11.2%10.8% for 2017. We expect2020. Property taxes decreased in 2022 due to recent legislative changes reducing both property taxes to increase astax assessment ratios and rates in Arizona. As we add new generating units and continue with improvements and expansions to our existing generating units andgeneration, transmission, and distribution facilities.facilities in future years, we anticipate property taxes may increase, though these increases will continue to be partially offset by the impacts of the recent legislative changes noted above.
Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions, and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Act"“Tax Act”) was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (SeeSee Note 54 for details of the impacts on the Company as of December 31, 2019.)2022. In APS'sAPS’s 2017 Rate Case Decision, the ACC approved the TEAM, which iswas being used to pass through the income tax effects to retail customers of the Tax Act. (SeeAs part of the 2019 Rate Case (defined above), all impacts of the Tax Act were removed from the TEAM and incorporated into APS’s base rates. The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in APS’s next rate case. See Note 43 for details of the TEAM.)
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (seedebt. See Note 7).6 for further details. 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.
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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 – 20192022 compared with 2018.
Our consolidated net income attributable to common shareholders for the year ended December 31, 20192022, was $538$484 million, compared with $511$619 million for the prior year. The results reflect an increasea decrease of approximately $30$114 million for the regulated electricity segment, which include higher depreciation and amortization expense primarily due to the absence of the Ocotillo modernization project and the Four Corners SCR project regulatory deferrals that ended upon the 2019 Rate Case effective date (see Note 3), increased plant assets and updated depreciation rates. In addition, the results reflect lower revenue driven by the LFCR alternative revenue treatment and higher operations and maintenance costs and tax expense due to amortization of excess deferred taxes as a result of the Tax Act,
expense. These negative factors were partially offset by lowerhigher revenue due todriven by the refunds provided to customers resulting from the Tax Act,effects of weather, customer usage and milder weathergrowth, increased transmission revenue and lower pension and other postretirement non-service credits.income taxes.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||||||||
| 2022 | 2021 | Net change | |||||||||||||||
| (dollars in millions) | |||||||||||||||||
| Regulated Electricity Segment: | |||||||||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,690 | $ | 2,645 | $ | 45 | |||||||||||
| Operations and maintenance | (983) | (951) | (32) | ||||||||||||||
| Depreciation and amortization | (753) | (651) | (102) | ||||||||||||||
| Taxes other than income taxes | (220) | (235) | 15 | ||||||||||||||
| Pension and other postretirement non-service credits — net | 98 | 113 | (15) | ||||||||||||||
| All other income and expenses, net | 23 | 61 | (38) | ||||||||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (255) | (233) | (22) | ||||||||||||||
| Income taxes (Note 4) | (75) | (110) | 35 | ||||||||||||||
| Less income related to noncontrolling interests (Note 17) | (17) | (17) | — | ||||||||||||||
| Regulated electricity segment income | 508 | 622 | (114) | ||||||||||||||
| All other | (24) | (3) | (21) | ||||||||||||||
| Net Income Attributable to Common Shareholders | $ | 484 | $ | 619 | $ | (135) | |||||||||||
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Year Ended December 31, | |||||||||||
| 2019 | 2018 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,425 | $ | 2,590 | $ | (165 | ) | ||||
| Operations and maintenance | (939 | ) | (1,025 | ) | 86 | ||||||
| Depreciation and amortization | (591 | ) | (581 | ) | (10 | ) | |||||
| Taxes other than income taxes | (219 | ) | (212 | ) | (7 | ) | |||||
| Pension and other postretirement non-service credits - net | 23 | 50 | (27 | ) | |||||||
| All other income and expenses, net | 61 | 59 | 2 | ||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (217 | ) | (218 | ) | 1 | ||||||
| Income taxes (Note 5) | 16 | (134 | ) | 150 | |||||||
| Less income related to noncontrolling interests (Note 19) | (19 | ) | (19 | ) | — | ||||||
| Regulated electricity segment income | 540 | 510 | 30 | ||||||||
| All other | (2 | ) | 1 | (3 | ) | ||||||
| Net Income Attributable to Common Shareholders | $ | 538 | $ | 511 | $ | 27 | |||||
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $165$45 million lowerhigher for the year ended December 31, 20192022, 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) | |||||||||||
| Refunds due to lower Federal corporate income tax rate (Note 4) | $ | (146 | ) | $ | — | $ | (146 | ) | |||
| Effects of weather | (32 | ) | (8 | ) | (24 | ) | |||||
| Lower renewable energy regulatory surcharges and higher purchased power, offset by operations and maintenance costs | (15 | ) | 2 | (17 | ) | ||||||
| Change in residential rate design (a) | 13 | — | 13 | ||||||||
| Lost fixed cost recovery | 8 | — | 8 | ||||||||
| Higher retail revenue due to higher customer growth, partially offset by the impacts of energy efficiency, distributed generation and changes in customer usage patterns | 10 | 5 | 5 | ||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (60 | ) | (61 | ) | 1 | ||||||
| Miscellaneous items, net | 5 | 10 | (5 | ) | |||||||
| Total | $ | (217 | ) | $ | (52 | ) | $ | (165 | ) | ||
| Increase (Decrease) | |||||||||||||||||
| Operating revenues | Fuel and purchased power expenses | Net change | |||||||||||||||
| (dollars in millions) | |||||||||||||||||
| Lower refunds in the current year related to the Tax Act (Note 3) | $ | 141 | $ | — | $ | 141 | |||||||||||
| Effects of weather | 77 | 19 | 58 | ||||||||||||||
| Higher retail revenue due to changes in customer usage patterns and customer growth, partially offset by the impacts of energy efficiency and distributed generation | 46 | 23 | 23 | ||||||||||||||
| Higher transmission revenues (Note 3) | 14 | — | 14 | ||||||||||||||
| Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs | 18 | 9 | 9 | ||||||||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | 425 | 426 | (1) | ||||||||||||||
| Lost fixed cost recovery (Note 3) | (54) | — | (54) | ||||||||||||||
| Impact of new retail base rates from 2019 Rate Case effective December 1, 2021 | (147) | — | (147) | ||||||||||||||
| Miscellaneous items, net | 2 | — | 2 | ||||||||||||||
| Total | $ | 522 | $ | 477 | $ | 45 | |||||||||||
Operations and maintenance. Operations and maintenance expenses decreased $86increased $32 million for the year ended December 31, 20192022, compared with the prior-year period primarily because of:
•an increase of $10 million primarily associated with the ballot initiative in 2018;
Depreciation and amortization. Depreciation and amortization expenses were $10$102 million higher for the year ended December 31, 20192022, compared with the prior-year period primarily due to $55 million for the Ocotillo modernization project and the Four Corners SCR project regulatory deferrals recorded in the prior year period that ended upon the 2019 Rate Case effective date and the related 2022 regulatory deferral amortization, and $47 million related to increased plant in service of $33 million, partially offset by the regulatory deferrals for the Four Corners SCR and Ocotillo modernization project of $19 million and the deferral of Navajo Plant costs of $4 million which is offset in operations and maintenance.updated depreciation rates.
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Taxes other than income taxes. Taxes other than income taxes were $7$15 million higherlower for the year ended December 31, 20192022, compared with the prior-year period primarily due to higherthe impacts of recent legislative changes reducing both property values.tax assessment ratios and rates in Arizona and property tax deferrals that ended upon the 2019 Rate Case effective date and the related 2022 property tax deferral amortization.
Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $27$15 million lower for the year ended December 31, 20192022, compared to the prior-year period primarily due to loweractual market returns being lower than estimated returns in 2018.2021.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $22 million higher for the year ended December 31, 2022, compared to the prior-year period primarily due to higher debt balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.
Income taxes. Income taxes were $35 million lower for the year ended December 31, 2022, compared with the prior-year period primarily due to amortizationlower pre-tax net income, partially offset by a net operating loss carryback benefit that the Company recognized during the first quarter of excess deferred taxes and2021.
All Other. All other earnings were $21 million lower pretax incomefor year ended December 31, 2022, compared with the prior-year period primarily due to the Clear Creek wind farm impairment write-off. See “BCE Matters” in the current year period (see Note 5).10 for additional details.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2019,2022, APS’s common equity ratio, as defined, was 52%50%. Its total shareholder equity was approximately $5.9$6.9 billion, and total capitalization was approximately $11.2$13.9 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.5$5.6 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.
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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.
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, 20192022, and 20182021 (dollars in millions):
Pinnacle West Consolidated
| 2019 | 2018 | 2022 | 2021 | |||||||||||||||
| Net cash flow provided by operating activities | $ | 957 | $ | 1,277 | Net cash flow provided by operating activities | $ | 1,242 | $ | 860 | |||||||||
| Net cash flow used for investing activities | (1,131 | ) | (1,193 | ) | Net cash flow used for investing activities | (1,618) | (1,387) | |||||||||||
| Net cash flow provided by (used for) financing activities | 179 | (92 | ) | |||||||||||||||
| Net increase (decrease) in cash and cash equivalents | $ | 5 | $ | (8 | ) | |||||||||||||
| Net cash flow provided by financing activities | Net cash flow provided by financing activities | 371 | 477 | |||||||||||||||
| Net decrease in cash and cash equivalents | Net decrease in cash and cash equivalents | $ | (5) | $ | (50) | |||||||||||||
Arizona Public Service Company
| 2022 | 2021 | ||||||||||
| Net cash flow provided by operating activities | $ | 1,230 | $ | 865 | |||||||
| Net cash flow used for investing activities | (1,549) | (1,391) | |||||||||
| Net cash flow provided by financing activities | 314 | 478 | |||||||||
| Net decrease in cash and cash equivalents | $ | (5) | $ | (48) | |||||||
| 2019 | 2018 | ||||||
| Net cash flow provided by operating activities | $ | 1,007 | $ | 1,255 | |||
| Net cash flow used for investing activities | (1,136 | ) | (1,187 | ) | |||
| Net cash flow provided by (used for) financing activities | 133 | (76 | ) | ||||
| Net increase (decrease) in cash and cash equivalents | $ | 4 | $ | (8 | ) | ||
Operating Cash Flows
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. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 ("ERISA"(“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 117%estimated to be 112% funded as of January 1, 20202023, and 112%was 139% as of January 1, 2019. Under GAAP, the qualified pension plan was 97% funded as of January 1, 2020 and 90% funded as of January 1, 2019. See Note 8 for additional details. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.2022. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $150$0 million in 2019 and $502022, $100 million in 2018.2021, and $100 million in 2020. The minimum required contributions for the pension plan are zero for the next three years. Weyears and we do not expect to make any voluntary contributions up to $100 million per year during the 2020-2022 period. With regard toin 2023, 2024 or 2025. Regarding contributions to our other postretirement benefit
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plan, we did not make a contributionany contributions in 20192022 or 2021 and 2018. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.in 2023, 2024 or 2025. The Company was reimbursed $30$26 million in 2019 and $722022, $24 million in 20182021, and $26 million in 2020 for prior years'years retiree medical claims from the other postretirement benefit plan trust assets. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 106% funded as of December 31, 2022, and our postretirement benefit plans were 159% funded, as measured for GAAP purposes at December 31, 2022. See Note 7 for additional details.
The 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. As of December 31, 2022, we have paid this cash deferral in full.
Investing Cash Flows
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, | |||||||||||||||||||||||
| 2023 | 2024 | 2025 | |||||||||||||||||||||
| APS | |||||||||||||||||||||||
| Generation: | |||||||||||||||||||||||
| Clean: | |||||||||||||||||||||||
| Nuclear Generation | $ | 120 | $ | 120 | $ | 120 | |||||||||||||||||
| Renewables and Energy Storage Systems (“ESS”) (a) | 240 | 345 | 400 | ||||||||||||||||||||
| Other Generation (b) | 265 | 245 | 245 | ||||||||||||||||||||
| Distribution | 520 | 530 | 530 | ||||||||||||||||||||
| Transmission | 260 | 300 | 300 | ||||||||||||||||||||
| Other (c) | 265 | 260 | 255 | ||||||||||||||||||||
| Total APS | $ | 1,670 | $ | 1,800 | $ | 1,850 | |||||||||||||||||
(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.
The table above does not include capital expenditures related to BCE projects.
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Estimated for the Year Ended December 31, | |||||||||||
| 2020 | 2021 | 2022 | |||||||||
| APS | |||||||||||
| Generation: | |||||||||||
| Clean: | |||||||||||
| Nuclear Generation | $ | 131 | $ | 123 | $ | 123 | |||||
| Renewables and Energy Storage Systems ("ESS") (a) | 121 | 490 | 671 | ||||||||
| Environmental | 44 | 53 | 44 | ||||||||
| Other Generation | 139 | 154 | 121 | ||||||||
| Distribution | 554 | 444 | 446 | ||||||||
| Transmission | 182 | 203 | 208 | ||||||||
| Other (b) | 160 | 183 | 112 | ||||||||
| Total APS | $ | 1,331 | $ | 1,650 | $ | 1,725 | |||||
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 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
APS’s consolidated net cash provided by financing activities was $133$314 million in 20192022 compared to $76$478 million in 2021, a decrease of net cash used in 2018, an increase of $209$164 million in net cash provided. The increaseprovided primarily due to a net decrease in net cash providedshort-term borrowings of $232 million and higher dividend payments of $9 million, partially offset by financing activities includes $797$78 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $418 million, lower equity infusion of $150 million and higher dividend payments of $20 million.debt.
Significant Financing Activities. On December 18, 2019,14, 2022, the Pinnacle West Board of Directors declared a dividend of $0.7825$0.865 per share of common stock, payable on March 2, 20201, 2023, to shareholders of record on February 3, 2020.1, 2023. During 2019,2022, Pinnacle West increased its indicated annual dividend from $2.95$3.40 per share to $3.13$3.46 per share. For the year ended December 31, 2019,2022, Pinnacle West'sWest’s total dividends paid per share of common stock were $3.00$3.42 per share, which resulted in dividend payments of $329$379 million.
Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 5 for more information on available credit facilities.
Other Financing Matters. See Note 1715 for information related to the change in our margin and collateral accounts.
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Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2019,2022, the ratio was approximately 52%58% for Pinnacle West and 47%51% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could "cross-default"“cross-default” other debt. See further discussion of "cross-default"“cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain "rating triggers"“rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain "cross-default"“cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain "cross-default"“cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
On December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.9 billion to $7.5 billion, and authorized APS’s short-term debt authorization equal to the 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). On December 15, 2022, the ACC issued a financing order approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term debt for purposes of the ACC financing orders. See Note 76 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 14, 202015, 2023, 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.period. 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 potential downward revision to our credit ratings.
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| Moody’s | Standard & Poor’s | Fitch | |||||||||||||||
| Pinnacle West | |||||||||||||||||
| Corporate credit rating | Baa1 | BBB+ | BBB+ | ||||||||||||||
| Senior unsecured | Baa1 | BBB | BBB+ | ||||||||||||||
| Commercial paper | P-2 | A-2 | F2 | ||||||||||||||
| Outlook | Negative | Negative | Negative | ||||||||||||||
| Corporate credit rating | A3 | ||||||||||||||||
| Senior unsecured | A3 | BBB+ | A- | ||||||||||||||
| Commercial paper | P-2 | A-2 | F2 | ||||||||||||||
| Outlook | Negative | Negative | |||||||||||||||
Contractual Obligations
•Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2019 (dollars2022. See Note 6.
•Pinnacle West and APS maintain committed revolving credit facilities. See Note 5 for short-term debt details.
•Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 3 and 10. Purchase obligations include capital expenditures and other obligations. See Note 10. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 8.
•APS holds certain contracts to purchase renewable energy credits in millions):compliance with the RES. See Notes 3 and 10.
| 2020 | 2021- 2022 | 2023- 2024 | Thereafter | Total | |||||||||||||||
| Long-term debt payments, including interest: (a) | |||||||||||||||||||
| APS | $ | 554 | $ | 398 | $ | 757 | $ | 7,405 | $ | 9,114 | |||||||||
| Pinnacle West | 460 | — | — | — | 460 | ||||||||||||||
| Total long-term debt payments, including interest | 1,014 | 398 | 757 | 7,405 | 9,574 | ||||||||||||||
| Short-term debt payments, including interest (b) | 115 | — | — | — | 115 | ||||||||||||||
| Fuel and purchased power commitments (c) | 569 | 1,217 | 1,176 | 5,318 | 8,280 | ||||||||||||||
| Renewable energy credits (d) | 36 | 66 | 58 | 133 | 293 | ||||||||||||||
| Purchase obligations (e) | 21 | 20 | 21 | 196 | 258 | ||||||||||||||
| Coal reclamation | 17 | 33 | 37 | 88 | 175 | ||||||||||||||
| Nuclear decommissioning funding requirements | 2 | 4 | 4 | 50 | 60 | ||||||||||||||
| Noncontrolling interests (f) | 23 | 46 | 39 | 143 | 251 | ||||||||||||||
| Operating lease payments (g) | 15 | 20 | 10 | 39 | 84 | ||||||||||||||
| Total contractual commitments | $ | 1,812 | $ | 1,804 | $ | 2,102 | $ | 13,372 | $ | 19,090 | |||||||||
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 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.
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Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings. Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities. We had $1,507$1,822 million of regulatory assets and $2,503$2,333 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2019.
2022. See Notes 1 and 43 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liabilityassets, 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 most relevant actuarial assumptions are the discount rate, the expected long-term rate of return on plan assets (“EROA”), and the assumed healthcare cost trend rates. Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense. To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years. Following are the most relevant actuarial assumptions:
Discount Rate. The discount rate is used to measure the plan liability and net periodic cost. For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future benefit payments to estimate the projected benefit obligation for each plan. This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year’s benefit payments by a spot rate to that year. The spot rates are derived from a yield curve composed of domestic AA rated corporate bonds.
EROA. The EROA is used to estimate earnings on invested funds over the long-term. For this assumption we consider historical experience and future expectations of asset classes utilized in the portfolio.
Healthcare Cost Trend Rates. We consider past performance and forecasts of health care costs and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes.
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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 20192022 reported pension liabilityassets and liabilities on the Consolidated Balance Sheets and our 20192022 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’sthe Consolidated Statements of Income (dollars in millions):
| Increase (Decrease) | ||||||||||||||
| Actuarial Assumption (a) | Impact on Pension Plans | Impact on Pension Expense | ||||||||||||
| Discount rate (b): | ||||||||||||||
| Increase 1% | $ | (238) | $ | 3 | ||||||||||
| Decrease 1% | 279 | 13 | ||||||||||||
| EROA: | ||||||||||||||
| Increase 1% | — | (27) | ||||||||||||
| Decrease 1% | — | 27 | ||||||||||||
| Increase (Decrease) | ||||||||
| Actuarial Assumption (a) | Impact on Pension Liability | Impact on Pension Expense | ||||||
| Discount rate: | ||||||||
| Increase 1% | $ | (388 | ) | $ | (11 | ) | ||
| Decrease 1% | 471 | 14 | ||||||
| Expected long-term rate of return on plan assets: | ||||||||
| Increase 1% | — | (22 | ) | |||||
| Decrease 1% | — | 22 | ||||||
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the obligation and expense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 20192022, other postretirement benefit obligation on the Pinnacle West’s Consolidated Balance Sheets and our 20192022 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 (b): | ||||||||||||||
| Increase 1% | $ | (39) | $ | (3) | ||||||||||
| Decrease 1% | 46 | 4 | ||||||||||||
| Healthcare cost trend rate (c): | ||||||||||||||
| Increase 1% | 43 | 8 | ||||||||||||
| Decrease 1% | (36) | (6) | ||||||||||||
| EROA – pretax: | ||||||||||||||
| Increase 1% | — | (7) | ||||||||||||
| Decrease 1% | — | 7 | ||||||||||||
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| Increase (Decrease) | ||||||||
| Actuarial Assumption (a) | Impact on Other Postretirement Benefit Obligation | Impact on Other Postretirement Benefit Expense | ||||||
| Discount rate: | ||||||||
| Increase 1% | $ | (104 | ) | $ | (1 | ) | ||
| Decrease 1% | 134 | 5 | ||||||
| Healthcare cost trend rate (b): | ||||||||
| Increase 1% | 124 | 9 | ||||||
| Decrease 1% | (98 | ) | (4 | ) | ||||
| Expected long-term rate of return on plan assets – pretax: | ||||||||
| Increase 1% | — | (4 | ) | |||||
| Decrease 1% | — | 4 | ||||||
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated.
(c)This assumes a 1% change in the initial and ultimate healthcare cost trend rate.
See Note 87 for further details about our pension and other postretirement benefit plans.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trusttrusts 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 1412 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, 20192022 are described further in Note 12.11.
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,trusts, other special use funds and benefit plan assets.
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 14Notes 12 and Note 20)18), 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, 20192022, and 2018.2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 20192022, and 20182021 (dollars in millions):
Pinnacle West – Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2022 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2023 | 4.56 | % | $ | 341 | 5.42 | % | $ | 51 | — | $ | — | |||||||||||||||||||||||||||
| 2024 | — | — | 5.10 | % | 450 | 3.35 | % | 250 | ||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 1.99 | % | 800 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| 2027 | — | — | — | — | 2.95 | % | 300 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 3.96 | % | 163 | 4.10 | % | 5,580 | ||||||||||||||||||||||||||||||
| Total | $ | 341 | $ | 664 | $ | 7,180 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 341 | $ | 664 | $ | 5,922 | ||||||||||||||||||||||||||||||||
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| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2.06 | % | $ | 115 | 2.16 | % | $ | 350 | 2.23 | % | $ | 450 | |||||||||||||||||||||||||||||||||||||||||||||||
| 2021 | — | — | — | — | — | — | 2021 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||||||||||||||||
| 2022 | — | — | — | — | — | — | 2022 | 0.18 | % | $ | 292 | 0.78 | % | $ | 150 | — | $ | — | |||||||||||||||||||||||||||||||||||||||||
| 2023 | — | — | — | — | — | — | 2023 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
| 2024 | — | — | — | — | 3.78 | % | 365 | 2024 | — | — | 0.85 | % | 150 | 3.35 | % | 250 | |||||||||||||||||||||||||||||||||||||||||||
| 2025 | 2025 | — | — | — | — | 1.99 | % | 800 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Years thereafter | — | — | 1.54 | % | 36 | 4.12 | % | 4,475 | Years thereafter | — | — | 0.22 | % | 36 | 3.87 | % | 5,480 | ||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 115 | $ | 386 | $ | 5,290 | Total | $ | 292 | $ | 336 | $ | 6,780 | ||||||||||||||||||||||||||||||||||||||||||||||
| Fair value | $ | 115 | $ | 386 | $ | 5,808 | Fair value | $ | 292 | $ | 336 | $ | 7,390 | ||||||||||||||||||||||||||||||||||||||||||||||
Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2018 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2019 | 2.99 | % | $ | 76 | — | $ | — | 8.75 | % | $ | 500 | ||||||||||
| 2020 | — | — | 3.02 | % | 150 | 2.23 | % | 550 | |||||||||||||
| 2021 | — | — | — | — | — | — | |||||||||||||||
| 2022 | — | — | — | — | — | — | |||||||||||||||
| 2023 | — | — | — | — | — | — | |||||||||||||||
| Years thereafter | — | — | 1.76 | % | 36 | 4.25 | % | 3,940 | |||||||||||||
| Total | $ | 76 | $ | 186 | $ | 4,990 | |||||||||||||||
| Fair value | $ | 76 | $ | 186 | $ | 5,048 | |||||||||||||||
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, 20192022, and 2018.2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 20192022, and 20182021 (dollars in millions):
APS — Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||||||||||||||||
Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||||||||||||||
| Interest | Interest | |||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2.12 | % | $ | 200 | 2.20 | % | $ | 150 | ||||||||||||||||||||||||||||||||||||||||||||
| 2021 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| 2022 | — | — | — | — | 2022 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||||||||||||||||||||||||||||
| 2023 | — | — | — | — | 2023 | 4.56 | % | $ | 325 | — | $ | — | — | $ | — | |||||||||||||||||||||||||||||||||||||
| 2024 | — | — | 3.78 | % | 365 | 2024 | — | — | — | — | 3.35 | % | 250 | |||||||||||||||||||||||||||||||||||||||
| 2025 | 2025 | — | — | — | — | 3.15 | % | 300 | ||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2026 | — | — | — | — | 2.55 | % | 250 | ||||||||||||||||||||||||||||||||||||||||||||
| 2027 | 2027 | — | — | — | — | 2.95 | % | 300 | ||||||||||||||||||||||||||||||||||||||||||||
| Years thereafter | 1.54 | % | 36 | 4.12 | % | 4,475 | Years thereafter | — | — | 3.96 | % | 163 | 4.10 | % | 5,580 | |||||||||||||||||||||||||||||||||||||
| Total | $ | 236 | $ | 4,990 | Total | $ | 325 | $ | 163 | $ | 6,680 | |||||||||||||||||||||||||||||||||||||||||
| Fair value | $ | 236 | $ | 5,508 | Fair value | $ | 325 | $ | 163 | $ | 5,466 | |||||||||||||||||||||||||||||||||||||||||
Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2018 | Rates | Amount | Rates | Amount | ||||||||||
| 2019 | �� | — | $ | — | 8.75 | % | $ | 500 | ||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| 2021 | — | — | — | — | ||||||||||
| 2022 | — | — | — | — | ||||||||||
| 2023 | — | — | — | — | ||||||||||
| Years thereafter | 1.76 | % | 36 | 4.25 | % | 3,940 | ||||||||
| Total | $ | 36 | $ | 4,690 | ||||||||||
| Fair value | $ | 36 | $ | 4,754 | ||||||||||
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| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2021 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2022 | 0.18 | % | $ | 279 | — | $ | — | — | $ | — | ||||||||||||||||||||||||||||
| 2023 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| 2024 | — | — | — | — | 3.35 | % | 250 | |||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 3.15 | % | 300 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 0.22 | % | 36 | 3.87 | % | 5,480 | ||||||||||||||||||||||||||||||
| Total | $ | 279 | $ | 36 | $ | 6,280 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 279 | $ | 36 | $ | 6,898 | ||||||||||||||||||||||||||||||||
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 fuels.natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our energy derivative positions in 2019 and 2018 (dollars in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Mark-to-market of net positions at beginning of year | $ | 107 | $ | (13) | |||||||
| Increase (decrease) in regulatory liability | (11) | 120 | |||||||||
| Mark-to-market of net positions at end of year | $ | 96 | $ | 107 | |||||||
| 2019 | 2018 | ||||||
| Mark-to-market of net positions at beginning of year | $ | (58 | ) | $ | (91 | ) | |
| Decrease (Increase) in regulatory asset | (15 | ) | 31 | ||||
| Recognized in OCI: | |||||||
| Mark-to-market losses realized during the period | 2 | 2 | |||||
| Change in valuation techniques | — | — | |||||
| Mark-to-market of net positions at end of year | $ | (71 | ) | $ | (58 | ) | |
The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 20192022, 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 | 2023 | 2024 | 2025 | 2026 | 2027 | Total Fair Value | ||||||||||||||||||||||||||||||||
| Observable prices provided by other external sources | $ | 70 | $ | 31 | $ | — | $ | — | $ | — | $ | 101 | ||||||||||||||||||||||||||
| Prices based on unobservable inputs | (14) | 9 | — | — | — | (5) | ||||||||||||||||||||||||||||||||
| Total by maturity | $ | 56 | $ | 40 | $ | — | $ | — | $ | — | $ | 96 | ||||||||||||||||||||||||||
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| Source of Fair Value | 2020 | 2021 | 2022 | 2023 | 2024 | Total fair value | ||||||||||||||||||
| Observable prices provided by other external sources | $ | (36 | ) | $ | (17 | ) | $ | (10 | ) | $ | (4 | ) | $ | — | $ | (67 | ) | |||||||
| Prices based on unobservable inputs | (2 | ) | — | — | — | (2 | ) | (4 | ) | |||||||||||||||
| Total by maturity | $ | (38 | ) | $ | (17 | ) | $ | (10 | ) | $ | (4 | ) | $ | (2 | ) | $ | (71 | ) | ||||||
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 at December 31, 2019 and 2018 (dollars in millions):
| December 31, 2022 Gain (Loss) | December 31, 2021 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 | $ | 12 | $ | (12) | $ | — | $ | — | |||||||||||||||
| Natural gas | 55 | (55) | 50 | (50) | |||||||||||||||||||
| Total | $ | 67 | $ | (67) | $ | 50 | $ | (50) | |||||||||||||||
December 31, 2019 Gain (Loss) | December 31, 2018 Gain (Loss) | ||||||||||||||
| Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||
| Mark-to-market changes reported in: | |||||||||||||||
| Regulatory asset (liability) (a) | |||||||||||||||
| Electricity | $ | — | $ | — | $ | 1 | $ | (1 | ) | ||||||
| Natural gas | 55 | (55 | ) | 44 | (44 | ) | |||||||||
| Total | $ | 55 | $ | (55 | ) | $ | 45 | $ | (45 | ) | |||||
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1715 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 | |||||
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) | |||||
Report of Independent Registered Public Accounting Firm(PCAOB ID No. 34) | |||||
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MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2019.2022. The effectiveness of our internal control over financial reporting as of December 31, 20192022, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.
February 21, 202027, 2023
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Arizona Public Service Company (“APS”), which is
| 2022 | 2021 | ||||||||||
| Net cash flow provided by operating activities | $ | 1,230 | $ | 865 | |||||||
| Net cash flow used for investing activities | (1,549) | (1,391) | |||||||||
| Net cash flow provided by financing activities | 314 | 478 | |||||||||
| Net decrease in cash and cash equivalents | $ | (5) | $ | (48) | |||||||
Operating Cash Flows
2022 Compared with 2021. Pinnacle West’s consolidated net cash provided by operating activities was $1,242 million in 2022 compared to $860 million in 2021, an increase of $382 million in net cash provided primarily due to $542 million higher cash receipts from electric revenues, $47 million lower payments for operations and maintenance costs, $100 million lower pension contributions and $79 million other changes in working capital, partially offset by $321 million higher fuel and purchased power costs, $47 million higher income taxes and $18 million higher interest payments. The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West in 2021.
Retirement plans and other postretirement benefits. Pinnacle West sponsors a wholly-owned subsidiaryqualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Company, is subjectEmployee Retirement Income Security Act of 1974 (“ERISA”) require us to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respectcontribute a minimum amount to the rates charged by public service utilitiesqualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. Under ERISA, the qualified pension plan was estimated to be 112% funded as of January 1, 2023, and was 139% as of January 1, 2022. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $0 million in Arizona. Management has determined it meets2022, $100 million in 2021, and $100 million in 2020. The minimum required contributions for the requirements underpension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2023, 2024 or 2025. Regarding contributions to our other postretirement benefit
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plan, we did not make any contributions in 2022 or 2021 and do not expect to make any contributions in 2023, 2024 or 2025. The Company was reimbursed $26 million in 2022, $24 million in 2021, and $26 million in 2020 for prior years retiree medical claims from the other postretirement benefit plan trust assets. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 106% funded as of December 31, 2022, and our postretirement benefit plans were 159% funded, as measured for GAAP purposes at December 31, 2022. See Note 7 for additional details.
The CARES Act allows employers to prepare its financial statements applyingdefer payments of the specialized rules to accountemployer 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 effectsperiod July 1, 2020, through December 31, 2020, that was approximately $18 million. As of cost-based rate regulation. AccountingDecember 31, 2022, we have paid this cash deferral in full.
Investing Cash Flows
2022 Compared with 2021. Pinnacle West’s consolidated net cash used for investing activities was $1,618 million in 2022 compared to $1,387 million in 2021, an increase of $231 million in net cash used primarily related to increased capital expenditures and BCE investment activity.
Capital Expenditures. The following table summarizes the estimated capital expenditures for the economicsnext three years:
Capital Expenditures
(dollars in millions)
| Estimated for the Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2024 | 2025 | |||||||||||||||||||||
| APS | |||||||||||||||||||||||
| Generation: | |||||||||||||||||||||||
| Clean: | |||||||||||||||||||||||
| Nuclear Generation | $ | 120 | $ | 120 | $ | 120 | |||||||||||||||||
| Renewables and Energy Storage Systems (“ESS”) (a) | 240 | 345 | 400 | ||||||||||||||||||||
| Other Generation (b) | 265 | 245 | 245 | ||||||||||||||||||||
| Distribution | 520 | 530 | 530 | ||||||||||||||||||||
| Transmission | 260 | 300 | 300 | ||||||||||||||||||||
| Other (c) | 265 | 260 | 255 | ||||||||||||||||||||
| Total APS | $ | 1,670 | $ | 1,800 | $ | 1,850 | |||||||||||||||||
(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.
The table above does not include capital expenditures related to BCE projects.
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Generation capital expenditures are comprised of various additions and disclosures,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 property, plantturbines, boilers, and equipment; regulatory assetsenvironmental 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 liabilities; operating revenues;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
2022 Compared with 2021. Pinnacle West’s consolidated net cash provided by financing activities was $371 million in 2022 compared to $477 million 2021, a decrease of $106 million in net cash provided primarily due to $150 million higher long-term debt repayments, a net decrease in short-term borrowings of $74 million and higher dividend payments of $9 million, partially offset by $129 million in higher issuances of long-term debt.
APS’s consolidated net cash provided by financing activities was $314 million in 2022 compared to $478 million in 2021, a decrease of $164 million in net cash provided primarily due to a net decrease in short-term borrowings of $232 million and higher dividend payments of $9 million, partially offset by $78 million in higher issuances of long-term debt.
Significant Financing Activities. On December 14, 2022, the Pinnacle West Board of Directors declared a dividend of $0.865 per share of common stock, payable on March 1, 2023, to shareholders of record on February 1, 2023. During 2022, Pinnacle West increased its indicated annual dividend from $3.40 per share to $3.46 per share. For the year ended December 31, 2022, Pinnacle West’s total dividends paid per share of common stock were $3.42 per share, which resulted in dividend payments of $379 million.
Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 5 for more information on available credit facilities.
Other Financing Matters. See Note 15 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, 2022, the ratio was approximately 58% for Pinnacle West and 51% 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.
On December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.9 billion to $7.5 billion, and authorized APS’s short-term debt authorization equal to the 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). On December 15, 2022, the ACC issued a financing order approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term debt for purposes of the ACC financing orders. See Note 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 15, 2023, 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. 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 potential downward revision to our credit ratings.
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| Moody’s | Standard & Poor’s | Fitch | |||||||||||||||
| Pinnacle West | |||||||||||||||||
| Corporate credit rating | Baa1 | BBB+ | BBB+ | ||||||||||||||
| Senior unsecured | Baa1 | BBB | BBB+ | ||||||||||||||
| Commercial paper | P-2 | A-2 | F2 | ||||||||||||||
| Outlook | Negative | Negative | Negative | ||||||||||||||
| APS | |||||||||||||||||
| Corporate credit rating | A3 | BBB+ | BBB+ | ||||||||||||||
| Senior unsecured | A3 | BBB+ | A- | ||||||||||||||
| Commercial paper | P-2 | A-2 | F2 | ||||||||||||||
| Outlook | Negative | Negative | Negative | ||||||||||||||
Contractual Obligations
Pinnacle West has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows:
•Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2022. See Note 6.
•Pinnacle West and APS maintain committed revolving credit facilities. See Note 5 for short-term debt details.
•Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 3 and 10. Purchase obligations include capital expenditures and other obligations. See Note 10. Commitments related to purchased power lease contracts are also considered fuel and purchased power; operationspower commitments. See Note 8.
•APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 3 and maintenance expense; and depreciation expense.10.
•APS is required to make payments to the rate-making policiesnoncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 17.
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 ACC. Rates are determinedfinancial statements and approvedduring the reporting period. Some of those 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.
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Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in regulatory proceedings based onour financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an analysis of costs to provide utility service and a return on, and recovery of, investmentexpense in the utility business.current period by unregulated companies. Regulatory decisions canassets represent incurred costs that have an impact on thebeen deferred because they are probable of future recovery ofin customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs the rate of return earned on investment, and the timing and amount of assetsexpected to be recovered by rates. 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 amountor amounts collected in excess of allowable deferred costs incurred and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expectsare refundable to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of
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 refundsignificant impact on our earnings and financial position. We review these assumptions on an annual basis and adjust them as necessary. The most relevant actuarial assumptions are the discount rate, the expected long-term rate of return on plan assets (“EROA”), and the assumed healthcare cost trend rates. Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense. To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years. Following are the most relevant actuarial assumptions:
Discount Rate. The discount rate is used to measure the plan liability and net periodic cost. For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future reduction inbenefit payments to estimate the projected benefit obligation for each plan. This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year’s benefit payments by a spot rate to that year. The spot rates that should be reported as regulatory liabilities. We also tested the effectivenessare derived from a yield curve composed of management’s controlsdomestic AA rated corporate bonds.
EROA. The EROA is used to estimate earnings on invested funds over the initial recognitionlong-term. For this assumption we consider historical experience and future expectations of asset classes utilized in the portfolio.
Healthcare Cost Trend Rates. We consider past performance and forecasts of health care costs and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes.
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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022 reported pension assets and liabilities on the Consolidated Balance Sheets and our 2022 reported pension expense, after consideration of amounts as property,capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions):
| Increase (Decrease) | ||||||||||||||
| Actuarial Assumption (a) | Impact on Pension Plans | Impact on Pension Expense | ||||||||||||
| Discount rate (b): | ||||||||||||||
| Increase 1% | $ | (238) | $ | 3 | ||||||||||
| Decrease 1% | 279 | 13 | ||||||||||||
| EROA: | ||||||||||||||
| Increase 1% | — | (27) | ||||||||||||
| Decrease 1% | — | 27 | ||||||||||||
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and equipment; regulatory assets or liabilities;decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the monitoringobligation and evaluationexpense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022, other postretirement benefit obligation on the Pinnacle West’s Consolidated Balance Sheets and our 2022 reported other postretirement benefit expense, after consideration of regulatory developmentsamounts 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 (b): | ||||||||||||||
| Increase 1% | $ | (39) | $ | (3) | ||||||||||
| Decrease 1% | 46 | 4 | ||||||||||||
| Healthcare cost trend rate (c): | ||||||||||||||
| Increase 1% | 43 | 8 | ||||||||||||
| Decrease 1% | (36) | (6) | ||||||||||||
| EROA – pretax: | ||||||||||||||
| Increase 1% | — | (7) | ||||||||||||
| Decrease 1% | — | 7 | ||||||||||||
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(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated.
(c)This assumes a 1% change in the initial and ultimate healthcare cost trend rate.
See Note 7 for further details about our pension and other postretirement benefit plans.
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 likelihoodvaluation of recovering costs in future rates orthe instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a future reduction in rates.discussion of accounting policies and Note 12 for fair value measurement disclosures.
Asset Retirement Obligations
We evaluatedrecognize an ARO for the Company’s disclosuresfuture 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 regulatorydecommissioning 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, specificallyAPS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.
AROs as of December 31, 2022 are described further in Note 11.
84
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trusts, other special use funds and benefit plan assets.
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 Notes 12 and 18), 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, 2022, and 2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2022, and 2021 (dollars in millions):
Pinnacle West – Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2022 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2023 | 4.56 | % | $ | 341 | 5.42 | % | $ | 51 | — | $ | — | |||||||||||||||||||||||||||
| 2024 | — | — | 5.10 | % | 450 | 3.35 | % | 250 | ||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 1.99 | % | 800 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| 2027 | — | — | — | — | 2.95 | % | 300 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 3.96 | % | 163 | 4.10 | % | 5,580 | ||||||||||||||||||||||||||||||
| Total | $ | 341 | $ | 664 | $ | 7,180 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 341 | $ | 664 | $ | 5,922 | ||||||||||||||||||||||||||||||||
85
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2021 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2022 | 0.18 | % | $ | 292 | 0.78 | % | $ | 150 | — | $ | — | |||||||||||||||||||||||||||
| 2023 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| 2024 | — | — | 0.85 | % | 150 | 3.35 | % | 250 | ||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 1.99 | % | 800 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 0.22 | % | 36 | 3.87 | % | 5,480 | ||||||||||||||||||||||||||||||
| Total | $ | 292 | $ | 336 | $ | 6,780 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 292 | $ | 336 | $ | 7,390 | ||||||||||||||||||||||||||||||||
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, 2022, and 2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2022, and 2021 (dollars in millions):
APS — Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2022 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2023 | 4.56 | % | $ | 325 | — | $ | — | — | $ | — | ||||||||||||||||||||||||||||
| 2024 | — | — | — | — | 3.35 | % | 250 | |||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 3.15 | % | 300 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| 2027 | — | — | — | — | 2.95 | % | 300 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 3.96 | % | 163 | 4.10 | % | 5,580 | ||||||||||||||||||||||||||||||
| Total | $ | 325 | $ | 163 | $ | 6,680 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 325 | $ | 163 | $ | 5,466 | ||||||||||||||||||||||||||||||||
86
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||||||||||||||||||||
| 2021 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||||||||||||||||||||
| 2022 | 0.18 | % | $ | 279 | — | $ | — | — | $ | — | ||||||||||||||||||||||||||||
| 2023 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| 2024 | — | — | — | — | 3.35 | % | 250 | |||||||||||||||||||||||||||||||
| 2025 | — | — | — | — | 3.15 | % | 300 | |||||||||||||||||||||||||||||||
| 2026 | — | — | — | — | 2.55 | % | 250 | |||||||||||||||||||||||||||||||
| Years thereafter | — | — | 0.22 | % | 36 | 3.87 | % | 5,480 | ||||||||||||||||||||||||||||||
| Total | $ | 279 | $ | 36 | $ | 6,280 | ||||||||||||||||||||||||||||||||
| Fair value | $ | 279 | $ | 36 | $ | 6,898 | ||||||||||||||||||||||||||||||||
Commodity Price Risk
We are exposed to the impact of rate regulation onmarket fluctuations in the financial statements,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 balances recordedhedged commodities.
The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions):
| December 31, 2022 | December 31, 2021 | ||||||||||
| Mark-to-market of net positions at beginning of year | $ | 107 | $ | (13) | |||||||
| Increase (decrease) in regulatory liability | (11) | 120 | |||||||||
| Mark-to-market of net positions at end of year | $ | 96 | $ | 107 | |||||||
The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 2022, by maturities and regulatory developments.
| Source of Fair Value | 2023 | 2024 | 2025 | 2026 | 2027 | Total Fair Value | ||||||||||||||||||||||||||||||||
| Observable prices provided by other external sources | $ | 70 | $ | 31 | $ | — | $ | — | $ | — | $ | 101 | ||||||||||||||||||||||||||
| Prices based on unobservable inputs | (14) | 9 | — | — | — | (5) | ||||||||||||||||||||||||||||||||
| Total by maturity | $ | 56 | $ | 40 | $ | — | $ | — | $ | — | $ | 96 | ||||||||||||||||||||||||||
87
The table below shows the probabilityimpact that hypothetical price movements of recovery10% 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, 2022 Gain (Loss) | December 31, 2021 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 | $ | 12 | $ | (12) | $ | — | $ | — | |||||||||||||||
| Natural gas | 55 | (55) | 50 | (50) | |||||||||||||||||||
| Total | $ | 67 | $ | (67) | $ | 50 | $ | (50) | |||||||||||||||
(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 regulatory assets or refund or future reductioninclusion in rates for regulatory liabilities based on applicable regulatory orders or precedence set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedence established byPSA, the ACC under similar circumstances and not
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| OPERATING REVENUES (NOTE 2) | $ | 3,471,209 | $ | 3,691,247 | $ | 3,565,296 | |||||
| OPERATING EXPENSES | |||||||||||
| Fuel and purchased power | 1,042,237 | 1,076,116 | 981,301 | ||||||||
| Operations and maintenance | 941,616 | 1,036,744 | 949,107 | ||||||||
| Depreciation and amortization | 590,929 | 582,354 | 534,118 | ||||||||
| Taxes other than income taxes | 218,579 | 212,849 | 184,347 | ||||||||
| Other expenses | 5,888 | 9,497 | 6,660 | ||||||||
| Total | 2,799,249 | 2,917,560 | 2,655,533 | ||||||||
| OPERATING INCOME | 671,960 | 773,687 | 909,763 | ||||||||
| OTHER INCOME (DEDUCTIONS) | |||||||||||
| Allowance for equity funds used during construction (Note 1) | 31,431 | 52,319 | 47,011 | ||||||||
| Pension and other postretirement non-service credits - net (Note 8) | 22,989 | 49,791 | 24,664 | ||||||||
| Other income (Note 18) | 50,263 | 24,896 | 4,006 | ||||||||
| Other expense (Note 18) | (17,880 | ) | (17,966 | ) | (21,539 | ) | |||||
| Total | 86,803 | 109,040 | 54,142 | ||||||||
| INTEREST EXPENSE | |||||||||||
| Interest charges | 235,251 | 243,465 | 219,796 | ||||||||
| Allowance for borrowed funds used during construction (Note 1) | (18,528 | ) | (25,180 | ) | (22,112 | ) | |||||
| Total | 216,723 | 218,285 | 197,684 | ||||||||
| INCOME BEFORE INCOME TAXES | 542,040 | 664,442 | 766,221 | ||||||||
| INCOME TAXES (Note 5) | (15,773 | ) | 133,902 | 258,272 | |||||||
| NET INCOME | 557,813 | 530,540 | 507,949 | ||||||||
| Less: Net income attributable to noncontrolling interests (Note 19) | 19,493 | 19,493 | 19,493 | ||||||||
| NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 538,320 | $ | 511,047 | $ | 488,456 | |||||
| WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC | 112,443 | 112,129 | 111,839 | ||||||||
| WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED | 112,758 | 112,550 | 112,367 | ||||||||
| EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | |||||||||||
| Net income attributable to common shareholders — basic | $ | 4.79 | $ | 4.56 | $ | 4.37 | |||||
| Net income attributable to common shareholders — diluted | $ | 4.77 | $ | 4.54 | $ | 4.35 | |||||
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 15 for a discussion of our credit valuation adjustment policy.
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| NET INCOME | $ | 557,813 | $ | 530,540 | $ | 507,949 | |||||
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | |||||||||||
| Derivative instruments: | |||||||||||
| Net unrealized loss, net of tax benefit (expense) of $0, ($78), and $24 (Note 17) | — | (78 | ) | (35 | ) | ||||||
| Reclassification of net realized loss, net of tax benefit of $375, $473, and $1,294 (Note 17) | 1,137 | 1,527 | 2,225 | ||||||||
| Pension and other postretirement benefits activity, net of tax benefit (expense) of $3,452, ($1,585), and $693 (Note 8) | (10,525 | ) | 4,397 | (3,370 | ) | ||||||
| Total other comprehensive income (loss) | (9,388 | ) | 5,846 | (1,180 | ) | ||||||
| COMPREHENSIVE INCOME | 548,425 | 536,386 | 506,769 | ||||||||
| Less: Comprehensive income attributable to noncontrolling interests | 19,493 | 19,493 | 19,493 | ||||||||
| COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 528,932 | $ | 516,893 | $ | 487,276 | |||||
DISCLOSURES ABOUT MARKET RISK
88
INDEX TO FINANCIAL STATEMENTS AND
| December 31, | |||||||
| 2019 | 2018 | ||||||
| ASSETS | |||||||
| CURRENT ASSETS | |||||||
| Cash and cash equivalents | $ | 10,283 | $ | 5,766 | |||
| Customer and other receivables | 266,426 | 267,887 | |||||
| Accrued unbilled revenues | 128,165 | 137,170 | |||||
| Allowance for doubtful accounts | (8,171 | ) | (4,069 | ) | |||
| Materials and supplies (at average cost) | 331,091 | 269,065 | |||||
| Fossil fuel (at average cost) | 14,829 | 25,029 | |||||
| Income tax receivable (Note 5) | 21,727 | — | |||||
| Assets from risk management activities (Note 17) | 515 | 1,113 | |||||
| Deferred fuel and purchased power regulatory asset (Note 4) | 70,137 | 37,164 | |||||
| Other regulatory assets (Note 4) | 133,070 | 129,738 | |||||
| Other current assets | 61,958 | 56,128 | |||||
| Total current assets | 1,030,030 | 924,991 | |||||
| INVESTMENTS AND OTHER ASSETS | |||||||
| Nuclear decommissioning trust (Notes 14 and 20) | 1,010,775 | 851,134 | |||||
| Other special use funds (Notes 14 and 20) | 245,095 | 236,101 | |||||
| Other assets | 96,953 | 103,247 | |||||
| Total investments and other assets | 1,352,823 | 1,190,482 | |||||
| PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10) | |||||||
| Plant in service and held for future use | 19,836,292 | 18,736,628 | |||||
| Accumulated depreciation and amortization | (6,637,857 | ) | (6,366,014 | ) | |||
| Net | 13,198,435 | 12,370,614 | |||||
| Construction work in progress | 808,133 | 1,170,062 | |||||
| Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19) | 101,906 | 105,775 | |||||
| Intangible assets, net of accumulated amortization of $647,276 and $591,202 | 290,564 | 262,902 | |||||
| Nuclear fuel, net of accumulated amortization of $137,330 and $137,850 | 123,500 | 120,217 | |||||
| Total property, plant and equipment | 14,522,538 | 14,029,570 | |||||
| DEFERRED DEBITS | |||||||
| Regulatory assets (Notes 1, 4 and 5) | 1,304,073 | 1,342,941 | |||||
| Operating lease right-of-use assets (Note 9) | 145,813 | — | |||||
| Assets for other postretirement benefits (Note 8) | 90,570 | 46,906 | |||||
| Other | 33,400 | 129,312 | |||||
| Total deferred debits | 1,573,856 | 1,519,159 | |||||
| TOTAL ASSETS | $ | 18,479,247 | $ | 17,664,202 | |||
| December 31, | |||||||
| 2019 | 2018 | ||||||
| LIABILITIES AND EQUITY | |||||||
| CURRENT LIABILITIES | |||||||
| Accounts payable | $ | 346,448 | $ | 277,336 | |||
| Accrued taxes | 144,899 | 154,819 | |||||
| Accrued interest | 53,534 | 61,107 | |||||
| Common dividends payable | 87,982 | 82,675 | |||||
| Short-term borrowings (Note 6) | 114,675 | 76,400 | |||||
| Current maturities of long-term debt (Note 7) | 800,000 | 500,000 | |||||
| Customer deposits | 64,908 | 91,174 | |||||
| Liabilities from risk management activities (Note 17) | 38,946 | 35,506 | |||||
| Liabilities for asset retirements (Note 12) | 11,025 | 19,842 | |||||
| Operating lease liabilities (Note 9) | 12,713 | — | |||||
| Regulatory liabilities (Note 4) | 234,912 | 165,876 | |||||
| Other current liabilities | 168,323 | 184,229 | |||||
| Total current liabilities | 2,078,365 | 1,648,964 | |||||
| LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) | 4,832,558 | 4,638,232 | |||||
| DEFERRED CREDITS AND OTHER | |||||||
| Deferred income taxes (Note 5) | 1,992,339 | 1,807,421 | |||||
| Regulatory liabilities (Notes 1, 4, 5 and 8) | 2,267,835 | 2,325,976 | |||||
| Liabilities for asset retirements (Note 12) | 646,193 | 706,703 | |||||
| Liabilities for pension benefits (Note 8) | 280,185 | 443,170 | |||||
| Liabilities from risk management activities (Note 17) | 33,186 | 24,531 | |||||
| Customer advances | 215,330 | 137,153 | |||||
| Coal mine reclamation | 165,695 | 212,785 | |||||
| Deferred investment tax credit | 196,468 | 200,405 | |||||
| Unrecognized tax benefits (Note 5) | 6,189 | 22,517 | |||||
| Operating lease liabilities (Note 9) | 51,872 | — | |||||
| Other | 159,844 | 147,640 | |||||
| Total deferred credits and other | 6,015,136 | 6,028,301 | |||||
| COMMITMENTS AND CONTINGENCIES (SEE NOTES) | |||||||
| EQUITY | |||||||
| Common stock, no par value; authorized 150,000,000 shares, 112,540,126 and 112,159,896 issued at respective dates | 2,659,561 | 2,634,265 | |||||
| Treasury stock at cost; 103,546 shares at end of 2019 and 58,135 shares at end of 2018 | (9,427 | ) | (4,825 | ) | |||
| Total common stock | 2,650,134 | 2,629,440 | |||||
| Retained earnings | 2,837,610 | 2,641,183 | |||||
| Accumulated other comprehensive loss (Note 21) | (57,096 | ) | (47,708 | ) | |||
| Total shareholders’ equity | 5,430,648 | 5,222,915 | |||||
| Noncontrolling interests (Note 19) | 122,540 | 125,790 | |||||
| Total equity | 5,553,188 | 5,348,705 | |||||
| TOTAL LIABILITIES AND EQUITY | $ | 18,479,247 | $ | 17,664,202 | |||
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | 2017 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
| Net Income | $ | 557,813 | $ | 530,540 | $ | 507,949 | |||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation and amortization including nuclear fuel | 664,140 | 650,955 | 610,629 | ||||||||
| Deferred fuel and purchased power | (82,481 | ) | (78,277 | ) | (48,405 | ) | |||||
| Deferred fuel and purchased power amortization | 49,508 | 116,750 | (14,767 | ) | |||||||
| Allowance for equity funds used during construction | (31,431 | ) | (52,319 | ) | (47,011 | ) | |||||
| Deferred income taxes | (1,479 | ) | 117,355 | 248,164 | |||||||
| Deferred investment tax credit | (3,938 | ) | (5,170 | ) | (4,587 | ) | |||||
| Change in derivative instruments fair value | — | — | (373 | ) | |||||||
| Stock compensation | 18,376 | 19,547 | 20,502 | ||||||||
| Changes in current assets and liabilities: | |||||||||||
| Customer and other receivables | (12,789 | ) | 37,530 | (93,797 | ) | ||||||
| Accrued unbilled revenues | 9,005 | (24,736 | ) | (4,485 | ) | ||||||
| Materials, supplies and fossil fuel | (51,826 | ) | (6,103 | ) | (6,683 | ) | |||||
| Income tax receivable | (21,727 | ) | — | 3,751 | |||||||
| Other current assets | (3,507 | ) | 33,844 | (10,580 | ) | ||||||
| Accounts payable | 50,641 | (14,602 | ) | (23,769 | ) | ||||||
| Accrued taxes | (9,920 | ) | 6,597 | 9,982 | |||||||
| Other current liabilities | (84,651 | ) | 28,174 | 19,154 | |||||||
| Change in margin and collateral accounts — assets | (247 | ) | 143 | (300 | ) | ||||||
| Change in margin and collateral accounts — liabilities | (125 | ) | (2,211 | ) | (533 | ) | |||||
| Change in unrecognized tax benefits | 2,704 | (1,235 | ) | 5,891 | |||||||
| Change in long-term regulatory liabilities | 124,221 | (109,284 | ) | 45,764 | |||||||
| Change in other long-term assets | (82,895 | ) | 78,604 | (68,480 | ) | ||||||
| Change in other long-term liabilities | (132,666 | ) | (48,958 | ) | (29,980 | ) | |||||
| Net cash flow provided by operating activities | 956,726 | 1,277,144 | 1,118,036 | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
| Capital expenditures | (1,191,447 | ) | (1,178,169 | ) | (1,408,774 | ) | |||||
| Contributions in aid of construction | 70,693 | 27,716 | 23,708 | ||||||||
| Allowance for borrowed funds used during construction | (18,528 | ) | (25,180 | ) | (22,112 | ) | |||||
| Proceeds from nuclear decommissioning trust sales and other special use funds | 719,034 | 653,033 | 542,246 | ||||||||
| Investment in nuclear decommissioning trust and other special use funds | (722,181 | ) | (672,165 | ) | (544,527 | ) | |||||
| Other | 11,452 | 1,941 | (19,078 | ) | |||||||
| Net cash flow used for investing activities | (1,130,977 | ) | (1,192,824 | ) | (1,428,537 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
| Issuance of long-term debt | 1,092,188 | 445,245 | 848,239 | ||||||||
| Repayment of long-term debt | (600,000 | ) | (182,000 | ) | (125,000 | ) | |||||
| Short-term borrowings and (repayments) — net | 54,275 | (7,000 | ) | (107,800 | ) | ||||||
| Short-term debt borrowings under revolving credit facility | 49,000 | 45,000 | 58,000 | ||||||||
| Short-term debt repayments under revolving credit facility | (65,000 | ) | (57,000 | ) | (32,000 | ) | |||||
| Dividends paid on common stock | (329,643 | ) | (308,892 | ) | (289,793 | ) | |||||
| Common stock equity issuance and purchases - net | 692 | (5,055 | ) | (13,390 | ) | ||||||
| Distributions to noncontrolling interests | (22,744 | ) | (22,744 | ) | (22,744 | ) | |||||
| Net cash flow provided by (used for) financing activities | 178,768 | (92,446 | ) | 315,512 | |||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 4,517 | (8,126 | ) | 5,011 | |||||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 5,766 | 13,892 | 8,881 | ||||||||
| CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 10,283 | $ | 5,766 | $ | 13,892 | |||||
| Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||
| Balance, December 31, 2016 | 111,392,053 | $ | 2,596,030 | (55,317 | ) | $ | (4,133 | ) | $ | 2,255,547 | $ | (43,822 | ) | $ | 132,290 | $ | 4,935,912 | ||||||||||||
| Net income | — | — | 488,456 | — | 19,493 | 507,949 | |||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (1,180 | ) | — | (1,180 | ) | |||||||||||||||||||||
| Dividends on common stock ($2.70 per share) | — | — | (301,492 | ) | — | — | (301,492 | ) | |||||||||||||||||||||
| Issuance of common stock | 424,117 | 18,775 | — | — | — | — | 18,775 | ||||||||||||||||||||||
| Purchase of treasury stock (a) | — | (216,911 | ) | (17,755 | ) | — | — | — | (17,755 | ) | |||||||||||||||||||
| Reissuance of treasury stock for stock-based compensation and other | — | 207,765 | 16,264 | — | — | — | 16,264 | ||||||||||||||||||||||
| Capital activities by noncontrolling interests | — | — | — | — | (22,743 | ) | (22,743 | ) | |||||||||||||||||||||
| Balance, December 31, 2017 | 111,816,170 | 2,614,805 | (64,463 | ) | (5,624 | ) | 2,442,511 | (45,002 | ) | 129,040 | 5,135,730 | ||||||||||||||||||
| Net income | — | — | 511,047 | — | 19,493 | 530,540 | |||||||||||||||||||||||
| Other comprehensive income | — | — | — | 5,846 | — | 5,846 | |||||||||||||||||||||||
| Dividends on common stock ($2.87 per share) | — | — | (320,927 | ) | — | — | (320,927 | ) | |||||||||||||||||||||
| Issuance of common stock | 343,726 | 19,460 | — | — | — | — | 19,460 | ||||||||||||||||||||||
| Purchase of treasury stock (a) | — | (129,903 | ) | (10,338 | ) | — | — | — | (10,338 | ) | |||||||||||||||||||
| Reissuance of treasury stock for stock-based compensation and other | — | 136,231 | 11,137 | — | — | — | 11,137 | ||||||||||||||||||||||
| Capital activities by noncontrolling interests | — | — | — | — | (22,743 | ) | (22,743 | ) | |||||||||||||||||||||
| Reclassification of income tax effects related to new tax reform (b) | — | — | 8,552 | (8,552 | ) | — | — | ||||||||||||||||||||||
| Balance, December 31, 2018 | 112,159,896 | 2,634,265 | (58,135 | ) | (4,825 | ) | 2,641,183 | (47,708 | ) | 125,790 | 5,348,705 | ||||||||||||||||||
| Net income | — | — | 538,320 | — | 19,493 | 557,813 | |||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (9,388 | ) | — | (9,388 | ) | |||||||||||||||||||||
| Dividends on common stock ($3.04 per share) | — | — | (341,893 | ) | — | — | (341,893 | ) | |||||||||||||||||||||
| Issuance of common stock | 380,230 | 25,296 | — | — | — | — | 25,296 | ||||||||||||||||||||||
| Purchase of treasury stock (a) | — | (121,493 | ) | (11,202 | ) | — | — | — | (11,202 | ) | |||||||||||||||||||
| Reissuance of treasury stock for stock-based compensation and other | — | 76,082 | 6,600 | — | — | — | 6,600 | ||||||||||||||||||||||
| Capital activities by noncontrolling interests | — | — | — | — | (22,743 | ) | (22,743 | ) | |||||||||||||||||||||
| Balance, December 31, 2019 | 112,540,126 | $ | 2,659,561 | (103,546 | ) | $ | (9,427 | ) | $ | 2,837,610 | $ | (57,096 | ) | $ | 122,540 | $ | 5,553,188 | ||||||||||||
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Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)
89 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING ( 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 February 90 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and the Board of Directors of Arizona Public Service Company
Operating Cash Flows 2022 Compared with 2021. Pinnacle West’s consolidated net cash provided by operating activities was $1,242 million in 2022 compared to $860 million in 2021, an increase of $382 million in net cash provided primarily due to $542 million higher cash receipts from electric revenues, $47 million lower payments for operations and maintenance costs, $100 million lower pension contributions and $79 million other changes in working capital, partially offset by $321 million higher fuel and purchased power costs, $47 million higher income taxes and $18 million higher interest payments. The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West in 2021. 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. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its 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. Under ERISA, the qualified pension plan was estimated to be 112% funded as of January 1, 2023, and was 139% as of January 1, 2022. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $0 million in 2022, $100 million in 2021, and $100 million in 2020. The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2023, 2024 or 2025. Regarding contributions to our other postretirement benefit 77 plan, we did not make any contributions in 2022 or 2021 and do not expect to make any contributions in 2023, 2024 or 2025. The Company was reimbursed $26 million in 2022, $24 million in 2021, and $26 million in 2020 for prior years retiree medical claims from the other postretirement benefit plan trust assets. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 106% funded as of December 31, 2022, and our postretirement benefit plans were 159% funded, as measured for GAAP purposes at December 31, 2022. See Note 7 for additional details. The 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. As of December 31, 2022, we have paid this cash deferral in full. Investing Cash Flows 2022 Compared with 2021. Pinnacle West’s consolidated net cash used for investing activities was $1,618 million in 2022 compared to $1,387 million in 2021, an increase of $231 million in net cash used primarily related to increased capital expenditures and BCE investment activity. Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years: Capital Expenditures (dollars in millions)
(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. The table above does not include capital expenditures related to BCE projects. 78 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 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 2022 Compared with 2021. Pinnacle West’s consolidated net cash provided by financing activities was $371 million in 2022 compared to $477 million 2021, a decrease of $106 million in net cash provided primarily due to $150 million higher long-term debt repayments, a net decrease in short-term borrowings of $74 million and higher dividend payments of $9 million, partially offset by $129 million in higher issuances of long-term debt. APS’s consolidated net cash provided by financing activities was $314 million in 2022 compared to $478 million in 2021, a decrease of $164 million in net cash provided primarily due to a net decrease in short-term borrowings of $232 million and higher dividend payments of $9 million, partially offset by $78 million in higher issuances of long-term debt. Significant Financing Activities. On December 14, 2022, the Pinnacle West Board of Directors declared a dividend of $0.865 per share of common stock, payable on March 1, 2023, to shareholders of record on February 1, 2023. During 2022, Pinnacle West increased its indicated annual dividend from $3.40 per share to $3.46 per share. For the year ended December 31, 2022, Pinnacle West’s total dividends paid per share of common stock were $3.42 per share, which resulted in dividend payments of $379 million. Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 5 for more information on available credit facilities. Other Financing Matters. See Note 15 for information related to the change in our margin and collateral accounts. 79 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, 2022, the ratio was approximately 58% for Pinnacle West and 51% 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. On December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.9 billion to $7.5 billion, and authorized APS’s short-term debt authorization equal to the 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). On December 15, 2022, the ACC issued a financing order approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term debt for purposes of the ACC financing orders. See Note 6 for further discussions of liquidity matters. Credit Ratings The ratings of securities of Pinnacle West and APS as of February 15, 2023, 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. 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 potential downward revision to our credit ratings. 80
Contractual Obligations Pinnacle West has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows: •Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2022. See Note 6. •Pinnacle West and APS maintain committed revolving credit facilities. See Note 5 for short-term debt details. •Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 3 and 10. Purchase obligations include capital expenditures and other obligations. See Note 10. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 8. •APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 3 and 10. •APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 17. 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 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. 81 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 $1,822 million of regulatory assets and $2,333 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2022. See Notes 1 and 3 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. We review these assumptions on an annual basis and adjust them as necessary. The most relevant actuarial assumptions are the discount rate, the expected long-term rate of return on plan assets (“EROA”), and the assumed healthcare cost trend rates. Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense. To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years. Following are the most relevant actuarial assumptions: Discount Rate. The discount rate is used to measure the plan liability and net periodic cost. For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future benefit payments to estimate the projected benefit obligation for each plan. This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year’s benefit payments by a spot rate to that year. The spot rates are derived from a yield curve composed of domestic AA rated corporate bonds. EROA. The EROA is used to estimate earnings on invested funds over the long-term. For this assumption we consider historical experience and future expectations of asset classes utilized in the portfolio. Healthcare Cost Trend Rates. We consider past performance and forecasts of health care costs and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes. 82 The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022 reported pension assets and liabilities on the Consolidated Balance Sheets and our 2022 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions):
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point. (b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the obligation and expense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values. The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022, other postretirement benefit obligation on the Pinnacle West’s Consolidated Balance Sheets and our 2022 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):
83 (a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point. (b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. (c)This assumes a 1% change in the initial and ultimate healthcare cost trend rate. See Note 7 for further details about our pension and other postretirement benefit plans. 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 12 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, 2022 are described further in Note 11. 84 MARKET AND CREDIT RISKS Market Risks Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trusts, other special use funds and benefit plan assets. 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 Notes 12 and 18), 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, 2022, and 2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2022, and 2021 (dollars in millions): Pinnacle West – Consolidated
85
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, 2022, and 2021. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2022, and 2021 (dollars in millions): APS — Consolidated
86
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. The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions):
The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 2022, 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.
87 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):
(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. Credit Risk We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 15 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. 88 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
89 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, 2022. The effectiveness of our internal control over financial reporting as of December 31, 2022, 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 27, 2023 90 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 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, 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 91 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 3 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 92 and 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, recent rate orders specific to APS and to other regulated entities in the same jurisdiction, and likelihood of success of legal appeals. 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 and legal bodies, 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 regulatory accounting 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; 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; and the implementation of new rates as ordered by the ACC. •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 intervenors, 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 APS’s 2022 rate application submitted to the ACC on October 28, 2022. •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 93 of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment. •We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read APS’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read APS’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision. /s/ Deloitte & Touche LLP February We have served as the 94 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF INCOME (dollars and shares in thousands, except per share amounts)
The accompanying notes are an integral part of the financial statements. 95 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 96 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 97 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 98 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 99 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (dollars in thousands, except per share amounts)
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes. The accompanying notes are an integral part of the financial statements. 100 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, 2022. The effectiveness of our internal control over financial reporting as of December 31, 2022, 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 27, 2023 101 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, 2022 and 2021, 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, 2022, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 102 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 3 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 103 and 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, recent rate orders specific to APS and to other regulated entities in the same jurisdiction, and likelihood of success of legal appeals. 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 and legal bodies, 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 regulatory accounting 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; 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; and the implementation of new rates as ordered by the ACC. •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 intervenors, 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 the Company’s 2022 rate application submitted to the ACC on October 28, 2022. •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 104 of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment. •We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, read the Company’s opening brief submitted to the Arizona Court of Appeals, read the ACC’s Answering Brief, read the Intervenors’ briefs, read the Company’s reply brief, and observed the Appeal Oral Arguments, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision. /s/ Deloitte & Touche LLP Tempe, Arizona February 27, 2023 We have served as the Company’s auditor since 1932. 105 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF INCOME (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 106 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 107 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED BALANCE SHEETS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 108 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED BALANCE SHEETS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 109 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 110 ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (dollars in thousands)
The accompanying notes are an integral part of the financial statements. 111 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 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 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 112 Regulatory Accounting APS is regulated by the ACC and the 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 Electric Revenues 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 See Notes 2 and 113 Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of 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 •AFUDC. Pinnacle West’s property, plant and equipment included in the December 31,
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 114 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 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, • •Nuclear plant — •Other generation — •Transmission — •Distribution — •General plant — Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was Asset Retirement Obligations APS has See Note 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. AFUDC was calculated by using a composite rate of 115 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 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 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. 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 116 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 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 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 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 117 $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 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 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):
The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
118 Intangible Assets We have no goodwill recorded and have separately disclosed other intangible assets, primarily 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). Our investments in the nuclear decommissioning trusts, coal reclamation escrow 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 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. Purchased power lease contracts may also include energy storage facilities. Lease costs relating to purchased power lease contracts are 119 reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 3. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 8 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, 2. Revenue Sources of Revenue The following table provides detail of Pinnacle
(a) Residential revenues for the year ended December 31, 2020, reflect a $24 million reduction related to the Arizona Attorney General matter. See Note 10.
Retail Electric Revenue. Pinnacle 120 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 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, 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, 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, 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. We continue to monitor the impacts of our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor, and allowance for doubtful accounts. 121
2022 Retail Rate Case APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in The principal provisions of APS’s application are: •a •an original cost rate base of $10.5 billion, which approximates the •the
•a 1% return on the •a •modification of its adjustment mechanisms including: ▪eliminate the ▪eliminate the ▪maintain as inactive the ▪maintain the ▪modify the performance incentive in the 122 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS •twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023. APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request. 2019 Retail Rate Case The principal provisions of •a test year comprised of •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:
•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 Base Fuel Rate; •authorization to defer until •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 200 123 •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 On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommended, among other things, (i) an $89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7%, (iii) a 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) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommended, among other things, (i) a $20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63%, (iii) a return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) the 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) the 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 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 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 Plant, 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. In 2021, APS committed an additional $0.9 million to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in its December 31, 2021 financials. 124 On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see “Four Corners SCR Cost Recovery” below for On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended. On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it. On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215.5 million of Four 125 Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action. The Arizona Court of Appeals heard oral arguments on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. APS cannot predict the outcome of Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers. APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline. APS cannot predict if the ACC will take any further action on this matter. Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $3.33 million to the Navajo Nation; (ii) $0.5 million to the Navajo County communities; and (iii) $1 million to the Hopi Tribe. Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments: (i) $0.5 million to the Navajo Nation for CCT; (ii) $1.1 million to the Navajo County Communities for CCT and economic development; and (iii) $1.25 million to the Hopi Tribe for CCT and economic development. The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation. Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory. Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities. APS and other interested parties filed comments on the report. On October 21, 2022, ACC Staff filed a revised report and proposed order. The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers. On December 8, 2022, the ACC voted against ACC Staff’s proposed order. APS cannot predict if the ACC will take any further action on this matter. Information Technology ACC Investigation On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making. APS is cooperating with the investigation. APS cannot predict the outcome of this matter. 126 2016 Retail Rate Case Filing 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, On August 15, 2017, the ACC approved APS customers 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. See “2022 Retail Rate Case”above for proposed modifications of adjustment mechanisms in the 2022 rate case. 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. 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 RES residential distributed energy requirement for 2020. On September 23, 2020, 127 waiver of the residential distributed energy requirements for 2020. 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 Demand Side Management Implementation Plan (“DSM Plan”). On July 1, 2020, APS filed its 2021 RES In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider All-Source requests for proposals (“RFP”) requirements and the IRP process. See “Energy Modernization Plan” below for more information. On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million. This budget includes funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES residential and non-residential distributed energy requirements for 2022. On May 18, 2022, the ACC approved the 2022 RES Implementation Plan, including an amendment requiring a stakeholder working group convene to develop a community solar program for the Commission’s consideration at a future date. On September 23, 2022, APS filed a community solar proposal in compliance with the ACC order that was informed by a stakeholder working group. APS is proposing a small, pilot-scale program size of up to 140MW that would be selected through a competitive RFP. The ACC has not yet ruled on the On July 1, 2022, APS filed its 2023 RES Implementation Plan and proposed a budget of approximately $86.2 million, excluding any funding offsets. This budget contains funding for programs to comply with Commission-approved initiatives, including the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a waiver of the RES 128 residential and non-residential distributed energy requirements for 2022. On November 10, 2022, the ACC approved the 2023 RES Implementation Plan, including APS’s requested waiver of the distributed energy requirement for 2023. In response to an ACC inquiry, the ACC Staff filed a report providing the history of APS’s long-term purchased power contract of the 280 MW Concentrating Solar Power Plant. This report outlines alternative options that the ACC could pursue to address the costs of this Demand Side Management Adjustor Charge.The ACC On December 31, 2019, APS filed its 2020 DSM Plan, which which 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. APS has refunded approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below. On December 31, 2020, APS filed its 2021 DSM Implementation Plan, which requested a budget of $63.7 million and continued 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. On April 6, 2021, APS filed an amended 2021 DSM Implementation Plan that proposed an additional one-time incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan. On July 13, 2021, the ACC approved the amended 2021 DSM Implementation Plan. On December 17, 2021, APS filed its 2022 DSM Implementation Plan in accordance with an extension granted in 2021. The 2022 DSM requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021. On November 10, 2022, the ACC approved the 2022 DSM Implementation Plan, including a proposed performance incentive. On November 30, 2022, 129 APS filed its 2023 DSM Implementation Plan, which requested a budget of $88 million. The ACC has not yet ruled on the 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; The following table shows the changes in the deferred fuel and purchased power regulatory asset for
On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh, On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh, which 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, which is the maximum permitted under the Plan of Administration for the PSA. This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in 130 future year resets of the PSA. 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 due to concerns of the impact on customers during COVID-19. In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50% of the rate increase taking effect in April 2021, and the remaining 50% taking effect in November 2021. The PSA rate implemented on April 1, 2021 was $0.001544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh. On November 1, 2021, the remaining increase was implemented to a rate of $0.003544 per kWh and consisted of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh. As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit to better understand the factors that contributed to the increase in fuel costs. On April 1, 2022, the ACC filed a final report of its third-party audit findings regarding APS’s fuel and purchased power costs for the period January 2019 through January 2021. The report contains an in-depth review of APS’s fuel and purchased power contracts, its monthly fuel accounting activities, its forecasting and dispatching procedures, and its monthly PSA filings, among other fuel-related activities. The report finds that the APS’s fuel processing accounting practices, dispatching procedures, and procedures for hedging activity are reasonable and appropriate. The report includes several recommendations for the ACC’s consideration, including review of current contracts, maintenance schedules, and certain changes and improvements to the schedules in APS’s monthly PSA filings. On December 27, 2022, ACC Staff filed a proposed order supporting adoption of the recommendations in the third-party audit report, and the ACC approved the proposed order on February 22, 2023. On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $0.007544 per kWh, which consisted of a forward component of $(0.004842) per kWh and a historical component of $0.012386 per kWh. The 2022 PSA rate is a $0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022. On November 30, 2022, APS filed its PSA rate for the PSA year beginning February 1, 2023. To address the growing under-collected PSA balance, APS also requested that one of three different options be adopted, including a temporary or permanent increase of the annual cap to $0.006 per kWh. As of October 31, 2022, the amount in the PSA balancing account was approximately $456 million of fuel and purchased power costs. On February 23, 2023, the ACC approved a rate of $0.019074 per kWh that will continue until further notice of the ACC. The rate will become effective with the first billing cycle in March 2023 and is designed to bring the PSA balancing account to near-zero over a 24-month period. APS will also be required to notify the ACC when the PSA balancing account approaches $500,000. On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to 131 Environmental Improvement Surcharge Transmission Rates, Transmission Cost Adjustor (“TCA”) 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 The formula rate is updated each year effective June 1 on the basis of On March Effective June 1, 132 rates. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, Effective June 1, Effective June 1, 2022, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $33 million for the 12-month period beginning June 1, 2022, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $6.4 million and retail customer rates would have decreased by approximately $26.6 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $2.4 million, resulting in a reduction to the residential rate and increases to commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2022. Lost Fixed Cost Recovery Mechanism.The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were On February As a result of the 133 rate for the subsequent year is set at zero. APS determined that the changes to the LFCR mechanism, On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that On February 15, 2023, APS filed a letter to the ACC docket stating that, in accordance with Decision No. 78585, APS and ACC Staff have agreed to move the filing date for the annual LFCR adjustment to July 31 each year. APS does not believe further ACC approval is needed to move the filing date, and APS intends to file its 2023 annual LFCR adjustment later in 2023 in accordance with the July 31 deadline. Tax Expense Adjustor On August 13, 2018, APS filed a 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 were recorded as a part of the balancing account and were addressed for recovery as part of the 2019 Rate Case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 134 the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit were recognized based upon APS’s seasonal kWh sales pattern. As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021, and all impacts of the Tax Act were removed from the TEAM and incorporated into Net Metering In addition, the ACC made the following 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. In accordance with the 2017 Rate Case Decision, APS filed its request for a 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 135 See Subpoena from Former Arizona Corporation Commissioner Robert Burns On August 25, 2016, Energy Modernization Plan On January 30, 2018, 136 retail energy served be renewable by The ACC Integrated Resource Planning ACC rules require utilities to develop Public Utility Regulatory Policies Act 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. 137 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 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 In accordance with the ACC 138 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Retail Electric Competition Rules On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona.Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application and intends to intervene to contest it. On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates of convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided his insights on the applicable law. On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200 to 300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier. The letter also states that similar programs should be designed for other Arizona regulated electric utilities. APS cannot predict the outcome of these future activities. 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 139 report concluded APS’s new rate comparison tool is APS received 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. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS 140 challenges nor the timing of when this matter will be resolved. See above for further discussion on the 2019 Rate Case decision. Cholla On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant (“Cholla”) and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if 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, Navajo Plant The APS has been recovering a return on and of the 141 Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands):
(a)This asset represents the future recovery of pension benefit obligations and expense 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. As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. See Note 7 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.” (e)Balance includes amounts for future regulatory consideration and amortization period determination. (f)See “Four Corners SCR Cost Recovery” discussion above. (g)Collected in retail rates. 142
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The detail of regulatory liabilities is as follows (dollars in thousands):
(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 7. (e)Balance includes amounts for future regulatory consideration and amortization period determination. 4. 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 143 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. 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 Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is 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):
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):
As of the balance sheet date, the tax year ended December 31, 144 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):
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):
Additionally, as of December 31, The components of income tax expense are as follows (dollars in thousands):
145 The following chart compares pretax income at the 21% statutory federal income tax rate
146 The components of the net deferred income tax liability were as follows (dollars in thousands):
As of December 31, 147 5. 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 The table below presents the consolidated credit facilities and the amounts available and outstanding
Pinnacle West APS At December 31, See 148 Debt Provisions On 149 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
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities. (b) The weighted-average interest rate for the variable rate pollution control bonds was 3.96% at December 31, 2022, and 0.22% at December 31, 2021. See additional details below. (c) The weighted-average interest rate was 5.1% at December 31, 2022, and 0.81% at December 31, 2021. See additional details below. (d) The weighted-average interest rate for the variable rate equity bridge loan is 5.18% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below. 150
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (e) The weighted-average interest rate for the variable rate construction facility is 5.71% at December 31, 2022 and will mature on the project’s commercial operation date, expected on or before August 15, 2023. See additional details below. The following table shows principal payments due on Pinnacle West’s, APS’s and
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):
Credit Facilities and Debt Issuances Pinnacle West On December 21, 2021, Pinnacle West entered into a $450 million term loan facility that matures December 20, 2024. On December 21, 2021, $150 million of the proceeds were received and recognized as long-term debt on the Consolidated Balance Sheets. On January 6, 2022, the remaining $300 million of proceeds was received and recognized on that date as long-term debt on the Consolidated Balance Sheets. The proceeds were used for general corporate purposes. On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that was set to mature June 30, 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 January 6, 2022, Pinnacle West repaid this term loan facility early. 151 On December 16, 2022, Pinnacle West entered into a $175 million term loan facility that matures December 16, 2024. The proceeds were received on January 6, 2023 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 6, 2023. APS On On September 15, 2022, APS remarketed $128 million of the Maricopa County, Arizona Pollution Control Corporation Revenue Refunding Bonds, 2009 Series B, C, D and E, due May 1, 2029 (the “Bonds”). The Bonds were originally issued on June 26, 2009, and prior to this remarketing were held as treasury bonds. Each series of the Bonds has a principal amount of $32 million. All series of the Bonds have been remarketed and issued in weekly variable interest rate modes and are classified as long-term debt on our Consolidated Balance Sheets. On November 8, 2022, APS issued On January See “Lines of Credit and Short-Term Borrowings” in Note BCE On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a 31 MW solar and battery storage project in Los Alamitos, California (“Los Alamitos”) that is under development by the subsidiary. The credit agreement consists of an approximately $33 million equity bridge loan facility, an approximately $42 million non-recourse construction facility, and an approximately $5 million letter of credit facility. In connection with the credit agreement, Pinnacle West has issued a guarantee of up to $42 million primarily relating to the equity bridge loan. As of December 31, 2022, $28 million has been drawn from the equity bridge loan and there is a $23 million outstanding balance for the construction facility and $2.5 million letters of credit outstanding under the credit facility. The equity bridge loan and construction facility mature and are due on the project’s commercial operation date, expected on or before August 15, 2023. BCE expects to convert the construction facility into a term loan upon the project’s commercial operation date.On October 19, 2022, BCE executed an interest rate swap to hedge the variable interest rate exposure of this credit facility. See Note 15. 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 152 capitalization not exceed 65%. At December 31, 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 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 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 directly 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 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. 153 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 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. Prior to 2020, 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. A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and 154 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):
The following table shows the plans’ changes in the benefit obligations and funded status
The following table shows
155 The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2022, and December 31, 2021, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2022 and 2021 is a non-qualified supplemental excess benefit retirement plan. The following table shows the amounts recognized on the Consolidated Balance Sheets
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31,
156
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
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 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 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 157 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. Based on the IPS, and given the pension
The permissible range is within +/ The following table presents the additional target allocations, as a percent of total pension plan assets, for the
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,
See Note 158 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 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 NAV for trusts investing in real estate is derived from the appraised values of the 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 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. 159 The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31,
(b)This category consists primarily of debt securities issued by municipalities and asset backed securities. (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. 160 The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31,
(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 161 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):
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 8. 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 In 1986, APS entered into agreements with APS has purchased power lease 162 The following table provides information related to our lease costs (dollars in thousands):
(a) Primarily relates to purchased power lease contracts.
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 163 The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
We recognize lease assets and liabilities upon lease commencement. At December 31,
164 The following tables provide other additional information related to operating lease
(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. 165
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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,
(c)PacifiCorp owns Cholla Unit 4 (see Note 3 for additional information), and APS operated the unit for PacifiCorp. Cholla Unit 4 166 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 APS has submitted Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act 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 167 decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited policies totals approximately 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 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):
(a)Total take-or-pay commitments are approximately $2.0 billion. The total net present value of these commitments is approximately $1.6 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):
168 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 Coal Mine Reclamation Obligations APS must reimburse certain coal providers Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act On August 6, 2013, the Roosevelt Irrigation District 169 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, On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving On February 28, 2022, EPA provided APS with a request for information under CERCLA related to APS’s Ocotillo power plant site located in Tempe, Arizona. In particular, EPA seeks information from APS regarding APS’s use, storage, and disposal of substances containing per-and polyfluoroalkyl (“PFAS”) compounds at the Ocotillo power plant site in order to aid EPA’s investigation into actual or threatened releases of PFAS into groundwater within the South Indian Bend Wash (“SIBW”) Superfund site. The SIBW Superfund site includes the APS Ocotillo power plant site. APS filed its response to this information request on April 29, 2022. On January 17, 2023, EPA contacted APS to inform the Company that it would be commencing on-site investigations within the SIBW site, including the Ocotillo power plant, and performing a remedial investigation and feasibility study related to potential PFAS impacts to groundwater over the next two to three years. At the present time, we are unable to predict the outcome of this matter and expenditures related to this matter cannot be reasonably estimated. 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 resulted in APS paying $24.75 million, approximately $24 million of which was returned to customers as restitution. 170 Four Corners SCR Cost Recovery As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. The Arizona Court of Appeals heard oral arguments on November 30, 2022. The Court took the matter under advisement and will issue its decision in due course. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2022. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See Note 3 for additional information regarding the Four Corners SCR cost recovery. 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 Regional Haze Rules. APS has received the final rulemaking imposing 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 171 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 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, including supporting the passage of new state legislation providing ADEQ with appropriate permitting authority for CCR under the state solid waste management program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits. The proposal remains pending. •On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019, to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal. We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final 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 172 approximately 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 Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal 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 173 Four Corners National Pollutant Discharge Elimination System Four Corners —4CA Matter On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as BCE Matters Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022. Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order. On October 7, 2022, the request for rehearing was denied by FERC. FERC has not ruled on the motion for stay. Clear Creek has filed a Petition for Review with the U.S. Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending. Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner. The Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors. These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion, 174 or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC. As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired. Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022. Pinnacle West’s Consolidated Statement of Income for the 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, 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. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, In connection with BCE’s acquisition of minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West 175 In connection with the 11. Asset Retirement Obligations In 2022, APS did not revise any cost estimates related to existing AROs, and no new AROs were necessary. In The following table shows the change in our
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
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 — 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 176 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. Recurring Fair Value Measurements We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning Cash Equivalents Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets. Risk Management Activities — Energy 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 177 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. Risk Management Activities — Interest Rate Derivatives Our Investments Held in Nuclear Decommissioning The nuclear decommissioning 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 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 Equity Securities The nuclear decommissioning 178 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 The nuclear decommissioning 179 Fair Value Tables The following table presents the fair value at December 31,
(a)Represents counterparty netting, margin, and collateral. See Note 15. (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. 180
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table presents the fair value at December 31,
(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 181 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. The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31,
(a)Includes swaps and physical and financial contracts. (b)Unobservable inputs were weighted by the relative fair value of the instrument.
(b)Unobservable inputs were weighted by the relative fair value of the instrument. 182
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table shows the changes in fair value for our risk management
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 Nonrecurring Fair Value Measurements As of December 31, 13. Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share
183 14. 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 Stock-Based Compensation Expense and Activity Compensation cost included in net income for stock-based compensation plans was $16 million in 2022, $18 million in As of December 31, The total fair value of shares vested was The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three
(a)Units granted includes awards that will be cash settled of 0 in 2022, 51,074 in 2021, and 184
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table
(a)Includes 69,413 of (b)The nonvested performance shares are reflected at target payout level. (c)We account for forfeitures as
Share-based liabilities paid relating to restricted stock units were Restricted Stock Units, Stock Grants, and Stock Units Restricted stock units are granted to officers and key Beginning in 2022, restricted stock unit awards are issued in stock. Awards include a dividend equivalent feature that allows each award to accrue dividends and treat them as reinvested, from the date of grant until the applicable vesting date. If the award is forfeited the employee is not entitled to the accrued reinvested dividends on those shares. Awards granted to retirement-eligible employees will vest on a pro-rata basis upon the Prior to 2022, awardees typically elected to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. 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. 185 Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the 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. Performance Share Awards Performance share awards are granted to officers and key employees. The awards contain Beginning in 2022, performance share awards contain three separate, unrelated performance criteria.The first performance criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the Prior to 2022, performance share awards had two performance criteria. The first performance criteria was based 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 186 compensation cost is recognized relating to the Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, 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 Energy Derivatives For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on energy derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on energy derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel
187 Gains and Losses from Energy Derivative Instruments The following table provides information about APS’s gains and losses from energy derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
(a)During the years ended December 31, 2022, 2021, and 2020, 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 energy derivative instruments in designated cash flow accounting hedging relationships have lapsed. The following table provides information about gains and losses from
(a)Amounts are before the effect of PSA deferrals. Energy Derivative Instruments in the Consolidated Balance Sheets Our energy 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 to be offset in the event of a default. 188 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following tables provide information about the fair value of
(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 $5,835 thousand and cash margin provided to counterparties of $28 thousand.
(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 $1,635 thousand and cash margin provided to counterparties of $50 thousand. 189
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Risk and Credit Related Contingent Features We are exposed to losses in the event of nonperformance or nonpayment by energy derivative counterparties and have risk management contracts with many energy derivative counterparties. As of December 31, Certain of our energy 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 energy 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). 190 The following table provides information about our energy derivative instruments that have credit-risk-related contingent features
(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 The following table provides detail of Pinnacle
191 Other Income and Other Expense - APS The following table provides detail of APS’s other income and other expense for
In 1986, APS entered into agreements with The As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $17 million for 2022, $17 million for 2021 and $19 million for 192 Our Consolidated Balance Sheets
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 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. We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Nuclear Decommissioning Trusts — Coal Reclamation Escrow Account 193 regulatory liabilities. Activities relating to APS coal mine reclamation escrow account investments are included within the other special use funds in the table below. Active Union Employee Medical Account APS The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of
(b)Represents net pending securities sales and purchases.
(a)As of December 31, 2021, the amortized cost basis of these available-for-sale investments is $972 million. (b)Represents net pending securities sales and purchases. 194
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table sets forth
(a)Proceeds are reinvested in the nuclear decommissioning trusts and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account.
Fixed Income Securities Contractual Maturities The fair value of APS’s fixed income securities, summarized by contractual maturities, at December 31,
195 The following table shows the changes in Pinnacle
(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 15. Changes in Accumulated Other Comprehensive Loss The following table shows the changes in
(a)These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 7. (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 15. 196
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands)
See Combined Notes to Consolidated Financial Statements. 197 PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (dollars in thousands)
See Combined Notes to Consolidated Financial Statements. 198 PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (dollars in thousands)
See Combined Notes to Consolidated Financial Statements. 199 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 200
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, 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, (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 (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, 201 ITEM 9B. OTHER INFORMATION None. ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. 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 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 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Reference is hereby made to “Ownership of Pinnacle West Stock” in the 202 Securities Authorized for Issuance Under Equity Compensation Plans The following table sets forth information as of December 31, Equity Compensation Plan Information
(a) This amount includes shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants. (b) The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price. (c) Awards under the 2021 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units. Additional shares cannot be awarded under the 2012 Plan and the 2007 Plan. However, if an award under the 2012 Plan or the 2007 Plan is forfeited, terminated or canceled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation, or expiration, may be added back to the shares available for issuance under the 2021 Plan. Equity Compensation Plans Approved By Security Holders Amounts in column (a) in the table above include shares subject to awards outstanding under 203 Equity Compensation Plans Not Approved by Security Holders The Company does not have any equity compensation plans under which shares can be issued that have not been approved by the shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Pinnacle West Reference is hereby made to “Audit Matters — Audit Fees and — Pre-Approval Policies” in the APS The following fees were paid to APS’s independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:
(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 (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 and environmental, social and governance assurance readiness performed in 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 204 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.
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aReports filed under File No. 1-4473 and 1-8962 were filed in the office of the 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. 225 ITEM 16. FORM 10-K SUMMARY None. 226 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.
Power of Attorney We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint 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.
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228 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.
Power of Attorney We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint 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.
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