Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. 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 Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes that appear in Item 1 of this report. 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 Part 1, Item 1A of the 2020 Form 10-K, and Part II, Item 1A of this report.

OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $22 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

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

COVID-19 Pandemic

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

We identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue arose. Additionally, efforts to ensure the health and safety of our employees resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations. We also established COVID-19 safety protocols, social distancing practices and offering virtual options whenever possible. The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic. Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace. As a result of these efforts, we were able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers and communities. In the summer of 2021, the Company began transitioning employees that were previously working remotely back to the workplace on a limited basis and began the reduction of our COVID-19 safety protocols and restrictions. Due to the COVID-19 Delta variant and increased transmission rates, the Company has delayed its full transition back to the workplace and COVID-19 safety protocols and restrictions remain in place.

Essential planned work and capital investments are continuing during the pandemic with priority given to support fire mitigation and summer storm efforts, as well as heat related outages. Raw material shortages and natural disasters are putting increased pressure on the global supply chain. APS is experiencing some delays in raw materials from Asia but currently, it has not experienced material supply chain shortages that impact its ability to serve its customers’ needs. 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 4 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.

The Company’s operations and maintenance expenses, exclusive of bad debt expense, increased by approximately $3.6 million for the period ended September 30, 2021 due to costs for personal protective equipment and other health and safety-related costs related to COVID-19. We expect the Company’s operation and maintenance expenses will continue to be impacted for 2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.

While the total expected impact of COVID-19 on future sales is currently unknown, APS 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 to commercial and industrial customers increased to levels in line with pre-COVID sales. APS cannot predict whether sales from commercial and industrial customers has fully recovered, but it expects sales trends to continue normalizing during 2021 as business activity continues to recover and more people return to work. Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

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

On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020 through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 31, 2022. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in both 2020 and 2021, but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements. See Note 1.

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment and waived late payment fees 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 is continuing to waive late payment fees. APS has experienced

and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium and the related write-offs of customer delinquent accounts. APS currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with this will result in a negative impact to its 2021 operating results of approximately $15 million to $25 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. These estimated impact amounts for 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy. See Note 4.

In February 2021, due to COVID-19, APS delayed the annual reset of the PSA. Rather than the increase being effective February 2021, the PSA reset was implemented with 50% of the increase effective April 2021 and the remaining 50% increase effective November 2021. See Note 4.

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

Strategic Overview

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

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. Our vision for APS and Arizona presents an opportunity to engage with customers, communities, employees, policymakers, shareholders and others to achieve a shared, sustainable vision for Arizona. This goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

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

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

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

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

2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix which includes all carbon-free resources like nuclear and demand-side management, and “renewable” is expressed as a percent 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’s Use of Coal-Fired Generation. Our commitment to end APS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation at Four Corners. APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of 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 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 is 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 3-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 within 12 months of the 2019 Rate Case decision and (v) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation within 12 months of the 2019 Rate Case decision. 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 4 for a discussion of the CCT plan.

In June 2021, APS and the owners of Four Corners entered into agreements to operate Four Corners seasonally beginning in Fall 2023, subject to the necessary approvals. Under seasonal operation, a single unit will remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages. In addition, the other unit will be operational throughout the summer season of June through October when customer demand is the highest. APS believes that operating Four Corners seasonally will bring environmental benefits and ensure continued service reliability for its customers, especially during Arizona’s hot summer months, as APS transitions to ceasing to use coal-fired generation by 2031. By moving to seasonal operations, Four Corners will become a more flexible resource that supports increasing amounts of clean energy, helping to compensate for the intermittent output of renewable resources. This change also helps ensure reliability of a critical energy source while reducing operations and maintenance costs. APS estimates that the shift to seasonal operations will reduce annual carbon emissions at Four Corners by an estimated 20-25%, as compared to current conditions.

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

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas. APS’s clean energy strategy includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS.

In September 2019, APS issued a request for proposal (“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 power purchase agreement (“PPA”) for a wind resource that is expected to be in service in the fourth quarter of 2021. Also in September 2019, APS issued a RFP that sought competitive proposals for up to 150 MW of APS-owned solar resources, designed with the flexibility to add energy storage as a future option. Negotiations pursuant to this RFP were terminated in March 2021. 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 both standalone energy storage and renewable energy plus energy storage resources and additional peaking capacity resources (collectively, the “December 2020 RFPs”). As a result of the amended all source RFP, APS executed a PPA in October 2021 for a 238 MW wind resource to be in service by June 2023, and also executed an engineering, procurement and construction contract in November 2021 for a 150 MW solar resource to be owned by APS and in service in early 2023. APS is still negotiating contracts for additional resources to be in service in 2024 in connection with the amended all source RFP.

The following table summarizes the resources in APS’s renewable energy portfolio that are in operation and under development as of September 30, 2021. 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.


	Net Capacity in Operation (MW)	Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar	247	—
Purchased Power Agreements Renewables:
Solar	310	160
Wind (a)	289	110
Geothermal	10	—
Biomass	14	—
Biogas	3	—
Total Purchased Power Agreements	626	270
Total Distributed Energy: Solar (b)	1,198	87	(c)
Total Renewable Portfolio	2,071	357

(a) Includes 90 MW wind PPA that is currently in operation that will be decommissioned in 2021 and rebuilt in the same year, together with an additional 110 MW, for a total of 200 MW, as a result of a PPA executed in September 2020.

(b) Includes rooftop solar facilities owned by third parties. Distributed generation is produced in Direct Current and is converted to Alternating Current for reporting purposes.

Energy Storage. APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation and, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional energy storage in the future.

In early 2018, APS entered into a 15-year PPA for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under the agreement was scheduled to begin in 2021; however, APS terminated the agreement, effective February 16, 2021, because project development could not be sufficiently advanced to support the expected in-service date. In 2018, APS issued a RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. These battery storage facilities are expected to be in service by June 2022. 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 all of APS's current APS-owned utility-scale solar facilities.

Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. APS completed its investigation of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs. These PPAs were also subject to ACC approval in order to allow for cost recovery through the PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

APS currently plans to install at least 850 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS is seeking energy storage resources through the December 2020 RFPs. In connection with the RFPs, in October 2021, APS entered into two energy storage PPAs with a total of 300 MW of capacity and one solar plus energy storage PPA with 60 MW of solar plus energy storage capacity. These resources are expected to be in service by June 2023 and June 2024. These PPAs are subject to ACC approval in order to allow for cost recovery through the PSA.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of September 30, 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
Purchase Power Agreements Energy Storage	—	150
Residential Energy Storage	10(a)	4
Total Energy Storage Portfolio	10	355

(a) This includes 10 MW of APS customer-owned batteries and 0.3 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. The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers. Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States. The plant is a critical asset to the Southwest, generating more than 32 million megawatt-hours annually – enough power for more than 4 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

We believe it is APS’s responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018 through September 2021, the average residential bill decreased by 6.41%, or $9.60, due to net reductions in cost recovery adjustor mechanisms.

Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and internal efficiencies. Through the initiative and existing cost management practices, in 2020, APS met its goal of $20 million in cost savings. In 2021, APS continues to drive this initiative to identify opportunities to streamline its business processes and deliver sustainable cost savings.

Participation in the EIM continues to be a tool for creating savings for APS’s customers from the real-time, voluntary market. APS continues to expect that its participation in EIM will lower its fuel and purchased-power costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources. APS continues to evaluate opportunities that benefit our customers and is exploring opportunities to move to a day-ahead market with the expectation of reliably achieving incrementally greater cost savings and using the region’s increasing renewable resources more efficiently. As part of that effort, APS is exploring several options. APS is in discussions with the current EIM operator, the California Independent System Operator, Inc. (“CAISO”), the Western Resource Adequacy Program, the Western Markets Exploratory Group, and the Southwest Power Pool. Each of these explorations also involve other entities and are being undertaken to evaluate the feasibility of creating a voluntary day-ahead market.

Reliable

While our energy mix evolves, the obligation to deliver reliable service to our customers remains. Notwithstanding the challenges presented by the COVID-19 pandemic, as well the Phoenix metropolitan experiencing the warmest June on record and its summer monsoon being the third-wettest over the last 41 years, APS continued to provide reliable service to its customers in 2021.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data.

Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government

entities and first responders and educate customers and communities. These programs contribute to customer reliability, responsible forest management and safe communities.

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

In April 2021, the CAISO sought FERC authorization for certain tariff changes intended to try to address risks associated with high heat weather events. Although APS is generally supportive of some of these changes, others would change the load, export, and wheeling priorities in a way that would unfairly benefit California entities at the expense of non-California entities. APS formally opposed those changes in front of FERC. On June 25, 2021, FERC issued an order accepting the CAISO’s proposed changes. On July 26, 2021, APS filed seeking a rehearing of FERC’s June 25, 2021 order. On August 26, 2021, FERC issued a notice indicating that the pending requests for rehearing were denied by operation of law and providing for further consideration. The requests for rehearing will be addressed in a future FERC order. APS cannot predict the outcome of these proceedings. Nor can PNW or APS predict whether energy shortages, market priorities, and/or price spikes due to extreme weather conditions will have an impact on its financial position, results of operations or cash flows.

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

Customers are at the core of what APS does every day and its focus remains on its customers and the communities it serves. It is APS’s goal to achieve an industry-leading best-in-class customer experience, including that APS improve its J.D. Power (“JDP”) customer satisfaction ratings from the fourth quartile to the first quartile of its peer set. Its third quarter 2021 JDP customer satisfaction score is tied with its 2020 performance, which was the highest in APS’s history and included being the most improved large utility from 2019 to 2020. APS’s focus remains on reliability and outage communications, value for price paid, billing and payment, corporate citizenship, communications, and customer care, which includes customers’ phone and digital experience. APS has continually improved its customer center performance with approximately 75% of its calls answered in 30 seconds or less and customers rating their phone experience in the first quartile nationally. APS has established a formal customer experience strategy council, which is a forum for sharing the Voice of the Customer and Voice of the Employee across the organization, ensuring a customer-centric culture, strategy, and plan.

APS is focused on continued awareness and outreach to its customers regarding assistance programs and resources to help customers, including energy efficiency programs, billing and payment programs, flexible and extended payment arrangements and providing customer options for assistance leveraging federal funding and agency assistance for utility bills. As of September 30, 2021, APS customers have received approximately $15 million from various sources of bill assistance with the largest amount coming from the Arizona Department of Economic Security’s Emergency Rental Assistance Program. This combined funding has assisted approximately 22,0000 customers. APS is also educating its customers on its “Safety Net” program, which allows customers to designate another party who will receive a copy of their bills without taking on any financial responsibility for the account in order to assist with delinquent payments and potential

disconnections. In addition, customers can also allow a guest designation to their aps.com profile where a third party can view billing information on-demand.

APS also convened a customer advisory board and consumer work group (stakeholder committee) in 2020 to serve as a vehicle for gathering valuable insights, directly from a cross-section of customers and stakeholders, that intends to keep APS apprised of customer needs, wants, and perspectives. The customer advisory board has met several times in 2021, addressing rate plan simplification, bill redesign and customer communications, among other things.

APS is also focused on educating customers on rate plans through monthly bill analysis and communicating to customers their most economical plan. APS is redesigning and improving the customer bill based on customer research, industry best practices and customer feedback. APS continues to see an increase in rate plan digital engagement, rate plan changes and rate comparison volumes on its website. As of September 25, 2021, 53.6% of its customers are on their most economical plan (as determined based on the time of the calculation).

Developing Clean Energy Technologies

Electric Vehicles

APS is making electric vehicle charging more accessible for its customers and helping Arizona businesses, schools and governments electrify their fleets. In 2021, APS continued its expansion of its Take Charge AZ Pilot Program. As of October 11, 2021, APS had installed approximately 315 charging ports at business customer locations with more stations expected to be added through 2022. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. In addition to the Level 2 charging stations, APS will begin construction of direct current fast charging stations that will be owned and operated by APS at five locations in Arizona. This project is projected to be completed during 2022, with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations. Charging at these stations will be accessible through the Electrify America charging network. APS also has a goal of 450,000 light-duty electric vehicles in its service territory by 2030.

Additionally, as part of the 2020 DSM Plan, the ACC approved programs for electric vehicles, including a residential program to measure electric vehicle charging as well as a $100 rebate to home builders for new home 240V charging station garage outlets.

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

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory (“INL”), Energy Harbor Corporation (“Energy Harbor”) and Xcel Energy Incorporated “Xcel”), was chosen by the DOE’s Office of Nuclear Energy to participate in a series of hydrogen production projects with the goal to improve the long-term economic competitiveness of the nuclear power industry. The multi-phase projects began in 2020 with 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 Palo Verde to produce hydrogen.

Based on the experience from Palo Verde’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, a newly formed subsidiary of Pinnacle West (“PNW Hydrogen”), 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 negotiation and execution of a definitive Cooperative Agreement funding instrument between PNW Hydrogen and DOE.

Carbon Capture

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

Regulatory Overview

On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) seeking an increase in annual retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that was the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS’s application were:

a test year comprised of 12 months ended June 30, 2019, adjusted as described below;
an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
the following proposed capital structure and costs of capital:


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

a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
a Base Fuel Rate of $0.030168 per kWh;
authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
a number of proposed rate and program changes for residential customers, including:

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

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

▪a flat bill/subscription rate pilot program;

proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and
continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).

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 2019 Rate Case. The ACC Staff recommended, among other things, (i) a $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 filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual customer bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) the CCT plan related to the closure or future closure of coal-fired generation facilities of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

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

Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers.

On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony. The ACC Staff reduced its recommended rate increase to $59.8 million, or an average annual customer bill increase of 1.82%. In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%.

The hearing concluded on March 3, 2021 and the post-hearing briefing concluded on April 30, 2021. In May 2021, the ACC declined to re-open the evidentiary record in the 2019 Rate Case to take additional evidence on topics raised by certain ACC Commissioners, including adjustor cost recovery mechanisms.

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 recommends, 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 additional information), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15% disallowance of annual amortization of Navajo Plant regulatory asset recovery, (vii) the denial of the request to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision. The 2019 Rate Case ROO also recommended that the CCT plan include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant. These amounts would be recoverable from APS’s customers through the Arizona Renewable Energy Standard and Tariff (“RES”) adjustment mechanism. APS filed exceptions on September 13, 2021 regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.

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 $500,000 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 within 12 months of the 2019 Rate Case decision and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation within 12 months of the 2019 Rate Case decision. 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.-8 p.m. to 4 p.m.-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. APS intends to file with the ACC an application for rehearing of the 2019

Rate Case. If the ACC does not approve this application, APS intends to appeal the decision in the 2019 Rate Case and is considering all other available and appropriate options. APS cannot predict the outcome of this proceeding.

APS expects to file an application with the ACC for its next general retail rate case in the near future but is continuing to evaluate the timing of such filing.

See Note 4 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 August 2, 2021, the 2019 Rate Case ROO recommended a disallowance of approximately $399 million of SCR plant investments and $61 million of SCR cost deferrals. On October 27, 2021, the ACC voted and passed an amendment to the 2019 Rate Case ROO that allows for recovery of approximately $194 million of SCR related plant investments and cost deferrals, resulting in a partial and combined disallowance of $215.5 million on the investments and deferrals. The amendment also requires that APS include the SCR plant investments and deferrals in rate base and recover, depreciate and amortize the investments and deferrals based on an end of life assumption of July 2031. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred and intends to legally challenge the ACC's $215.5 million disallowance. Based on APS's review and analysis of the amendment to the 2019 Rate Case ROO and its intent to legally challenge the disallowance, APS has not reflected an impairment or write-off related to this regulatory action as of September 30, 2021. If the amended 2019 Rate Case ROO is ultimately upheld, APS may be required to record a charge to its results of operations of up to $215.5 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. As of September 30, 2021, the SCR plant investments and SCR cost deferral balances reported on our condensed consolidated balance sheet are approximately $331 million and $77 million, net of accumulated deferred income taxes, respectively. See Note 4 for additional information regarding the Four Corners SCR cost recovery.

Arizona Attorney General Matter

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

Financial Strength and Flexibility

Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Other Subsidiaries

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

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

El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund. As of September 30, 2021, El Dorado has contributed approximately $10 million to the Energy Impact Partners fund. Additionally, El Dorado committed to a $25 million investment in invisionAZ Fund, which is a fund focused on analyzing, investing, managing and otherwise dealing with investments in privately held early stage and emerging growth technology companies and businesses primarily based in the State of Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in the State of Arizona. The investment will be made by El Dorado as investments are selected by the invisionAZ Fund.

Key Financial Drivers

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

Electric Operating Revenues. For the years 2018 through 2020, retail electric revenues comprised approximately 95% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.2% for the nine-month period ended September 30, 2021 compared with the prior-year period. For the three years 2018 through 2020, APS’s customer growth averaged 2.0% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2021 and that average annual growth will be in the range of 1.5% to 2.5% through 2024 based on our assessment of steady population growth in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 3.8% for the nine-month period ended September 30, 2021 compared with the prior-year period. While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were residential sales being stronger than anticipated due to continued work-from-home policies, a strong improvement in sales to commercial and industrial customers, and the ramp-up of new data center customers. Though 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 to commercial and industrial customers increased to levels in line with pre-COVID sales. APS cannot predict whether sales from commercial and industrial customers has fully recovered, but it expects sales trends to continue normalizing during 2021 as business activity continues to recover and more people return to work.

For the three years 2018 through 2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of 3.0% to 4.0% for 2021 and that average annual growth will be in the range of 3.5% to 4.5% through 2024, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. This projected sales growth range now includes the impacts of new, large manufacturing facilities, which are expected to contribute to average annual growth in the range of 1.0% to 2.0% through 2024. This projected sales growth range also includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers develop more usage history. These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, larger manufacturing facilities not coming to Arizona as expected, a diminishing shift to remote work, slower than expected commercial and industrial expansions, or acceleration of the expected effects of customer conservation, energy efficiency, distributed renewable generation initiatives.

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

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

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

Operations and Maintenance Expenses**.** Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation,

transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

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

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

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.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 3). 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.

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 Act was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. See Note 14 for details of the impacts on the Company as of September 30, 2021. In APS’s 2017 rate case decision, the ACC approved a Tax Expense Adjustor Mechanism which will be used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)

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 — Three-month period ended September 30, 2021 compared with three-month period ended September 30, 2020.

Our consolidated net income attributable to common shareholders for the three months ended September 30, 2021 was $340 million, compared with consolidated net income attributable to common shareholders of $346 million for the prior-year period. The results reflect a decrease of approximately $7 million for the regulated electricity segment primarily due to lower revenue driven by the effects of weather, and higher depreciation and amortization expense, partially offset by higher customer usage and customer growth, increased transmission revenue and higher pension and other postretirement non-service credits.

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


	Three Months Ended September 30,
	2021		2020		Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	882	$	900	$	(18)
Operations and maintenance	(231)		(235)		4
Depreciation and amortization	(164)		(153)		(11)
Taxes other than income taxes	(58)		(55)		(3)
Pension and other postretirement non-service credits - net	28		14		14
All other income and expenses, net	19		16		3
Interest charges, net of allowance for borrowed funds used during construction	(59)		(57)		(2)
Income taxes	(72)		(77)		5
Less income related to noncontrolling interests (Note 6)	(4)		(5)		1
Regulated electricity segment income	341		348		(7)
All other	(1)		(2)		1
Net Income Attributable to Common Shareholders	$	340	$	346	$	(6)

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $18 million lower for the three months ended September 30, 2021 compared with the prior-year period. The following table summarizes the major components of this change:


	Increase (Decrease)
	Operating revenues		Fuel and purchased power expenses		Net change
	(dollars in millions)



Effects of weather	$	(96)	$	(23)	$	(73)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	89		92		(3)
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs	5		(2)		7
Higher transmission revenues (Note 4)	16		—		16
Higher retail revenue due to customer growth and changes in customer usage patterns, partially offset by the impacts of energy efficiency and distributed generation	47		12		35

Miscellaneous items, net	(5)		(5)		—
Total	$	56	$	74	$	(18)

Operations and maintenance. Operations and maintenance expenses decreased $4 million for the three months ended September 30, 2021 compared with the prior-year period primarily because of:

A decrease of $6 million primarily related to customer support funds, personal protective equipment and other health and safety-related costs for COVID-19 response;
A decrease of $4 million for costs related to transmission and distribution;
A decrease of $4 million in nuclear generation costs;
An increase of $8 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; and
An increase of $2 million in other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $11 million higher for the three months ended September 30, 2021 compared to the prior-year period primarily due to increased plant in service of $8 million and lower regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $3 million.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $14 million higher for the three months ended September 30, 2021 compared to the prior-year period primarily due to actual market returns exceeding estimated returns in 2020.

Income taxes. Income taxes were $5 million lower for the three months ended September 30, 2021 compared with the prior-year period primarily due to lower pre-tax income.

Operating Results — Nine-month period ended September 30, 2021 compared with nine-month period ended September 30, 2020.

Our consolidated net income attributable to common shareholders for the nine months ended September 30, 2021 was $591 million, compared with consolidated net income attributable to common shareholders of $570 million for the prior-year period. The results reflect an increase of approximately $25 million for the regulated electricity segment, primarily due to higher revenue driven by higher customer growth and usage, higher pension and other postretirement non-service credits, higher transmission revenue, and lower refunds in the current year related to the Tax Act, partially offset by the effects of weather, higher depreciation and amortization expense, higher income taxes, including lower amortization of excess deferred taxes and higher operations and maintenance expense.

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


	Nine Months Ended September 30,
	2021		2020		Net Change
	(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses	$	2,104	$	2,062	$	42
Operations and maintenance	(689)		(674)		(15)
Depreciation and amortization	(480)		(459)		(21)
Taxes other than income taxes	(176)		(168)		(8)
Pension and other postretirement non-service credits - net	84		42		42
All other income and expenses, net	51		49		2
Interest charges, net of allowance for borrowed funds used during construction	(173)		(170)		(3)
Income taxes	(114)		(98)		(16)
Less income related to noncontrolling interests (Note 6)	(13)		(15)		2
Regulated electricity segment income	594		569		25
All other	(3)		1		(4)
Net Income Attributable to Common Shareholders	$	591	$	570	$	21

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $42 million higher for the nine months ended September 30, 2021 compared with the prior-year period. The following table summarizes the major components of this change:


	Increase (Decrease)
	Operating revenues		Fuel and purchased power expenses		Net change
	(dollars in millions)



Higher retail revenue due to customer growth and changes in customer usage patterns, partially offset by the impacts of energy efficiency and distributed generation	$	87	$	25	$	62
Higher transmission revenues (Note 4)	21		—		21
Lower refunds in the current year related to the Tax Act (Note 4)	17		—		17
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs	8		(4)		12
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals	114		119		(5)
Effects of weather	(82)		(19)		(63)
Miscellaneous items, net	(8)		(6)		(2)
Total	$	157	$	115	$	42

Operations and maintenance. Operations and maintenance expenses increased $15 million for the nine months ended September 30, 2021 compared with the prior-year period primarily because of:

An increase of $19 million related to employee benefits;
An increase of $11 million in fossil generation costs primarily due to higher planned outages and higher operating costs;
An increase of $10 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;
A decrease of $11 million primarily related to customer support funds, personal protective equipment and other health and safety-related costs for COVID-19 response;
A decrease of $7 million for costs related to transmission, distribution and customer service; and
A decrease of $7 million for corporate resources and other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $21 million higher for the nine months ended September 30, 2021 compared to the prior-year period primarily due to increased plant in service of $20 million.

Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $42 million higher for the nine months ended September 30, 2021 compared to the prior-year period primarily due to actual market returns exceeding estimated returns in 2020.

Income taxes. Income taxes were $16 million higher for the nine months ended September 30, 2021 compared with the prior-year period primarily due to lower amortization of excess deferred taxes and higher pre-tax income, partially offset by a net operating loss carryback benefit that the Company recognized during the first quarter of 2021.

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 September 30, 2021, APS’s common equity ratio, as defined, was 51%. Its total shareholder equity was approximately $6.6 billion, and total capitalization was approximately $13.1 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $5.2 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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

Summary of Cash Flows

Our consolidated change in cash and cash equivalents for the period ended September 30, 2021 compared to December 31, 2020 was a decrease of $34 million. The change is primarily driven by cash used for capital expenditures, fuel and purchased power and operations and maintenance costs, and dividend payments, which is partially offset by higher cash receipts from electric revenues, increased long-term debt issuances and lower long-term debt repayments. The following tables present net cash provided by (used for) operating, investing and financing activities (dollars in millions):

Pinnacle West Consolidated


	Nine Months Ended September 30,				Net
	2021		2020		Change
Net cash flow provided by operating activities	$	661	$	773	$	(112)
Net cash flow used for investing activities	(962)		(956)		(6)
Net cash flow provided by financing activities	267		355		(88)
Net change in cash and cash equivalents	$	(34)	$	172	$	(206)

Arizona Public Service Company


	Nine Months Ended September 30,				Net
	2021		2020		Change
Net cash flow provided by operating activities	$	651	$	771	$	(120)
Net cash flow used for investing activities	(970)		(961)		(9)
Net cash flow provided by financing activities	281		362		(81)
Net change in cash and cash equivalents	$	(38)	$	172	$	(210)

Operating Cash Flows

Nine-month period ended September 30, 2021 compared with nine-month period ended September 30, 2020. Pinnacle West’s consolidated net cash provided by operating activities was $661 million in 2021, compared to $773 million in 2020, a decrease of $112 million in net cash provided by operating activities primarily due to $205 million higher fuel and purchased power costs, $80 million higher payments for operations and maintenance costs and $11 million higher interest payments, partially offset by $157 million higher cash receipts from electric revenues and $32 million other changes in working capital.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 124% funded as of January 1, 2021 and 117% as of January 1, 2020. Under GAAP, the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, 2020. See Note 5 for additional details. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We have made voluntary contributions of $100 million to our pension plan in 2021. The minimum required contributions for the pension plan are zero for the next

three years. We do not expect to make voluntary pension contributions in 2022 and 2023. We do not expect to make any contributions over this period to our other postretirement benefit plans. We continue to monitor COVID-19 and its impact on our retirement plans and other postretirement benefits but we believe, due to our liability driven investment strategy, which helps to minimize the impact of market volatility on our plan’s funded status, our pension plan’s funded status, as measured for GAAP purposes, is still above 95% funded as of September 30, 2021.

Investing Cash Flows

Nine-month period ended September 30, 2021 compared with nine-month period ended September 30, 2020. Pinnacle West’s consolidated net cash used for investing activities was $962 million in 2021, compared to $956 million in 2020, an increase of $6 million primarily related to increased capital expenditures, partially offset by investing cash activity related to 4CA.

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

Capital Expenditures

(dollars in millions)


	Estimated for the Year Ended December 31,
	2021		2022		2023		2024
APS
Generation:
Clean:
Nuclear Generation	$	114	$	110	$	120	$	110
Renewables and Energy Storage Systems (“ESS”) (a)	143		230		210		450

Other Generation (b)	210		250		270		190
Distribution	602		510		530		500
Transmission	240		250		210		210
Other (c)	191		175		185		190
Total APS	$	1,500	$	1,525	$	1,525	$	1,650

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

(b)Includes generation environmental projects

(c)Primarily information systems and facilities projects

Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing traditional generation. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewable and energy storage, and upgrades and capital replacements of various nuclear and traditional generation 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

Nine-month period ended September 30, 2021 compared with nine-month period ended September 30, 2020. Pinnacle West’s consolidated net cash provided by financing activities was $267 million in 2021, compared to $355 million in 2020, a decrease of $88 million in net cash provided by financing activities primarily due to $887 million in lower issuances of long-term debt and higher dividend payments of $16 million, partially offset by lower long-term debt repayments of $800 million and a net decrease in short-term borrowing of $13 million.

APS’s consolidated net cash provided by financing activities was $281 million in 2021, compared to $362 million in 2020, a decrease of $81 million in net cash provided by financing activities primarily due to $540 million in lower issuances of long-term debt and higher dividend payments of $17 million, partially offset by lower long-term debt repayments of $350 million and a net increase in short-term borrowing of $125 million.

Significant Financing Activities. On November 4, 2021, the Pinnacle West Board of Directors declared a dividend of $0.85 per share of common stock, payable on December 1, 2021 to shareholders of record on November 16 , 2021. This represents an increase in the indicated annual dividend from $3.32 per share to $3.40 per share.

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 programs, to finance indebtedness, and other general corporate purposes.

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan facility with a new 364-day $31 million term loan facility that would have matured May 4, 2021. Borrowings under the facility bore interest at Eurodollar Rate plus 1.40% per annum. Pinnacle West repaid this agreement on April 27, 2021.

On August 16, 2021, APS issued $450 million of 2.2% unsecured senior notes that mature December 15, 2031. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper, replenish cash used to fund capital expenditures, and for general corporate purposes.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures 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 May 28, 2021, Pinnacle West replaced its $200 million revolving credit facility that would have matured on July 11, 2023, with a new $200 million revolving credit facility that matures on May 28, 2026. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle

West’s senior unsecured debt credit ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At September 30, 2021, Pinnacle West had no outstanding borrowings under its revolving credit facility, no letters of credit outstanding under the credit facility and no outstanding commercial paper borrowings.

On May 28, 2021, APS replaced its two $500 million revolving credit facilities that would have matured in June 2022 and July 2023, with two new $500 million revolving credit facilities that total $1 billion and that mature on May 28, 2026. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings and the agreements include a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. These facilities are available to support APS’s general corporate purposes, including support for APS’s $750 million commercial paper program, for bank borrowings or for issuances of letters of credit. At September 30, 2021, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding under the credit facilities and $125 million of outstanding commercial paper borrowings.

See “Financial Assurances” in Note 8 for a discussion of separate outstanding letters of credit and surety bonds.

Other Financing Matters. See Note 7 for information related to the change in our margin and collateral accounts.

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 September 30, 2021, the ratio was approximately 54% for Pinnacle West and 49% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.

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

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

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).

Credit Ratings

The ratings of securities of Pinnacle West and APS as of November 3, 2021 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. On October 12, 2021, Fitch Ratings downgraded the issuer ratings of the Company and APS from A- to BBB+ and the senior unsecured ratings of the Company and APS from A- and A to BBB+ and A-, respectively, with a negative outlook retained. Fitch Ratings also affirmed the commercial paper ratings of the Company and APS at F2. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.


	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Corporate credit rating	A3	A-	BBB+
Senior unsecured	A3	BBB+	BBB+
Commercial paper	P-2	A-2	F2
Outlook	Under Review for Downgrade	CreditWatch Negative	Negative

APS
Corporate credit rating	A2	A-	BBB+
Senior unsecured	A2	A-	A-
Commercial paper	P-1	A-2	F2
Outlook	Under Review for Downgrade	CreditWatch Negative	Negative

Off-Balance Sheet Arrangements

See Note 6 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Contractual Obligations

As of September 30, 2021, our fuel and purchased power and purchase obligation commitments have increased from the information provided in our 2020 Form 10-K. The increase is primarily due to new purchased power and energy storage commitments of approximately $695 million. The majority of the changes relate to 2026 and thereafter.

Other than the item described above, there have been no material changes, as of September 30, 2021, outside the normal course of business in contractual obligations from the information provided in our 2020

Form 10-K. See Note 3 for discussion regarding changes in our short-term and long-term debt obligations. See Note 6 for discussion regarding changes to our contractual obligations related to the Palo Verde sale leaseback transactions.

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. There have been no changes to our critical accounting policies since our 2020 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2020 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

In July 2021, a new accounting standard, ASU 2021-05, was issued that amends lessor’s accounting treatment for certain lease transactions with variable lease payments. The new guidance will be effective for us on January 1, 2022, with no expected material impacts. See Note 17 for additional information related to this new accounting standard.

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 Trusts, other special use funds (see Note 11 and Note 12), and benefit plan assets. The Nuclear Decommissioning Trusts, 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.

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 derivative positions (dollars in millions):


	Nine Months Ended September 30,
	2021		2020
Mark-to-market of net positions at beginning of period	$	(13)	$	(71)
Increase in regulatory liability	208		76
Recognized in OCI:
Mark-to-market losses realized during the period	—		—
Change in valuation techniques	—		—
Mark-to-market of net positions at end of period	$	195	$	5

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at September 30, 2021 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” in Item 8 of our 2020 Form 10-K and Note 11 for more discussion of our valuation methods.



Source of Fair Value	2021		2022		2023		2024		2025		Total Fair Value
Observable prices provided by other external sources	$	40	$	100	$	42	$	13	$	—	$	195
Prices based on unobservable inputs	—		—		—		—		—		—
Total by maturity	$	40	$	100	$	42	$	13	$	—	$	195

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 Condensed Consolidated Balance Sheets (dollars in millions):



	September 30, 2021				December 31, 2020
	Gain (Loss)				Gain (Loss)
	Price Up 10%		Price Down 10%		Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity	$	—	$	—	$	4	$	(4)
Natural gas	56		(56)		49		(49)
Total	$	56	$	(56)	$	53	$	(53)

(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 7 for a discussion of our credit valuation adjustment policy.

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