What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-02-24 · 362 added, 279 removed, 448 unchanged (59% of the section changed)

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COVID-19 Pandemic

The COVID-19 pandemic continues to be a rapidly evolving situation.

It has led to economic disruption and volatility in financial markets worldwide.

The 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 have identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue were to arise.

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

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

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

Essential planned work and capital investments are continuing during the pandemic, with some non-essential planned work postponed to the first quarter of 2021.

APS has continuous discussions with suppliers on manpower and supply issues pertaining to COVID-19 and has measures in place to continue to monitor resource needs and supply chain adequacy.

At this time, APS does not believe it has any material supply chain risks due to COVID-19 that would impact its ability to serve customers’ needs.

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

We expect the Company’s operation and maintenance expenses will continue to be impacted for 2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.

While the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic.

From March 13, 2020 through December 31, 2020, the cumulative impact in weather-normalized usage was approximately a 1% increase.

During that period, APS’s retail electric residential weather-normalized sales increased 5%, and its retail electric commercial and industrial weather-normalized sales decreased 4% in the aggregate.

APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat during 2021 as business activity continues to recover and more people return to work.

Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.

On March 31, 2020, a stay at home order became effective for the state of Arizona and remained in effect until May 16, 2020, when it was lifted and Arizona began reopening.

In June 2020, Arizona saw an increase in the number of COVID-19 cases, hospitalizations, and deaths.

Accordingly, on June 29, 2020, the governor of Arizona closed bars, indoor gyms and fitness clubs or centers, indoor movie theaters, water parks and tubing operations until July 27, 2020 as a partial reversal of the state’s reopening and to mitigate the spread of COVID-19.

On July 23, 2020, the governor of Arizona extended these closures and they remained in place until August 27, 2020, when bars, gyms and movie theaters reopened with certain restrictions.

We cannot predict the impact of the spread of COVID-19 in Arizona, whether there will be additional reclosures and how any such reclosures will impact our financial position, results of operations or cash flows.

We are continuing to monitor the impacts of COVID-19.

As a result of the COVID-19 pandemic, in mid-March 2020, the commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020.

In mid-April 2020, we were again able to utilize the commercial paper market and we have paid down the entire amount of the revolving credit facilities that were utilized as a result of the commercial paper market failure.

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 variants 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, rising inflation, COVID-19 related work force disruptions and natural disasters are putting increased pressure on the global supply chain.

APS is experiencing some delays in finished materials and tight labor markets.

To date, APS has not experienced labor or material supply chain shortages that have significantly impacted its ability to serve its customers’ needs.

However, shortages are causing minor delays, and shifting of work projects based on material availability.

If APS continues to experience delays in materials, it could experience an increase in purchased power costs for summer generation needs.

Such increased purchased power costs would be expected to be recoverable through the PSA.

See Note 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 $4.3 million for the year ended December 31, 2021, primarily due to costs for personal protective equipment and other health and safety-related costs related to COVID-19.

We do not expect the Company’s operation and maintenance expenses to be materially impacted in 2022 by 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 from commercial and industrial customers increased to levels in line with pre-COVID-19 sales but residential sales continued to be higher than pre-COVID-19 sales.

Based on past experience, a 1% variation in our annual residential and small commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $5 million.

The Coronavirus Aid, Relief, and Economic Security (CARES) Act 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.

We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020, through December 31, 2020, which was approximately $18 million.

We paid half of this cash deferral by December 31, 2021, and the remainder will be paid 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 2020, but does not impact prior years.

Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs.

The change did not have a material impact on our financial statements (see Note 1.)

Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020.

In addition, APS waived all late payment fees during this suspension period.

On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020.

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.

Due to COVID-19, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020, until December 31, 2020.

The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater.

APS will continue to waive late payment fees until October 15, 2021.

APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic.

The Summer Disconnection Moratorium (see Note 4), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic.

APS also currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with this will result in a negative impact to its 2021 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic.

These estimated impact amounts for 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy.

Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see Note 4).

On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers.

On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see Note 4).

As of December 31, 2020, APS had refunded approximately $43 million to customers.

The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period.

This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings.

APS has spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”).

The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million.

An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a

maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates.

Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance.

The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less.

As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined.

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

APS voluntarily began waiving late payment fees of its customers on March 13, 2020, and 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.

See Note 4 for additional information regarding the Summer Disconnection Moratorium.

The Summer Disconnection Moratorium, the suspension of disconnections due to COVID-19 and the increased bad debt expense associated with both events resulted in a negative impact to its 2021 operating results of approximately $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.

APS expects that the Summer Disconnection Moratorium, the suspension of disconnections due to COVID-19 and the increased bad debt expense associated with this will continue to negatively impact its operating results for the foreseeable future in amounts similar to 2020 and 2021.

The estimated impact depends on certain current assumptions, including, but not limited to, customer behaviors, population, and employment growth.

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.

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

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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:

As Arizona stewards, we do what is right for the people and prosperity of Arizona.

Our vision is to create a sustainable energy future for Arizona through providing clean, affordable, and reliable energy.

We can accomplish our visions through collaboration with customers, communities, employees, policymakers, shareholders, and other stakeholders.

Our clean energy 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 clean energy goals consist of three parts:

• A 2050 goal to provide 100% clean, carbon-free electricity;

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By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy.

Clean is measured as percent of energy mix which includes carbon-free resources like nuclear and demand-side management, and renewable is expressed as a percent of retail sales.

This target will

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.

“ 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.

End APS’s Use of Coal-Fired Generation.

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In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.

APS un derstands 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.

APS understands that the transition away from coal-fired power plants toward a clean energy future will pose unique economic challenges for the communities around these plants.

We worked collaboratively with stakeholders and leaders of the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired power plants on the communities surrounding those facilities to propose a comprehensive Coal Community Transition (“CCT”) plan.

The proposed framework provides substantial financial and economic development support to build new economic opportunities and addresses a transition strategy for plant employees.

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 supports the Navajo Nation, where the Four Corners Power Plant is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant.

The CCT plan is currently pending ACC approval.

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 three-year period that total $10 million to the Navajo Nation, (ii) a $1 million one-time payment to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (iii) a $500,000 one-time payment to the Navajo County communities within 60 days of the 2019 Rate Case decision, (iv) up to $1.25 million for electrification of homes and businesses on the Hopi reservation and (v) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation.

The payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant.

All ordered payments and expenditures would be recoverable through rates.

See Note 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 governmental approvals and conditions associated with changes in plant ownership.

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.

APS’s IRP (see Note 4 for additional information) establishes the path to meeting our clean energy commitment and maintaining reliable electric service for our customers.

APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources.

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.

Our IRP rapidly adds clean energy and storage resources while maintaining reliable and affordable service.

Its near-term actions are focused on clean energy and positive customer outcomes and includes:

(a) competitive solicitations to procure clean energy resources such as solar, wind, energy storage, and DSM resources, all of which lead to a cleaner grid;

and (b) strategic, short-term wholesale market purchases from a combination of existing merchant natural gas units, neighboring utility systems and wholesale market participants that ensure operational reliability.

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas that supports our commitment to clean energy, which is already strengthened by Palo Verde, the nation’s largest carbon-free, clean energy resource, that provides the foundation for reliable and affordable service for APS customers.

APS’s longer-term clean energy strategy includes pursuing the right mix of purchased power contracts for new facilities, procurement of new facilities to be owned by APS, and the ongoing development of distributed energy resources.

This balance will ensure an appropriately diverse portfolio designed to achieve the same operational reliability and customer affordability as APS’s near-term strategies.

In addition, APS is actively seeking to include future facility purchase options in its PPAs that will enable investments with greater financial flexibility.

APS uses competitive “all source” requests for proposal (“RFPs”) to pursue market resources that meet its system needs and offer the best value for customers.

APS selects projects based on cost and commercial viability, taking into consideration timing and likelihood of successful contracting and development.

Under current market conditions, APS must aggressively contract for resources that can withstand supply chain and other geopolitical pressures.

Available projects are guided by IRP timelines and quantities and APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the RFP process.

Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio” in Item 1 for details regarding APS’s renewable energy resources.

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

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

In December 2020, APS issued two additional RFPs:

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

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

As a result of the all source RFP, APS executed a PPA in October 2021 for a 238 MW wind resource to be in service by June 2023, and also executed an

engineering, procurement, and construction contract in November 2021 for a 150 MW solar resource to be owned by APS and in service in early 2023.

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

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

Energy Storage .

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

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

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

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

In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites.

Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site.

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

On August 2, 2021, APS executed a contract for an additional 60 MW of utility-owned energy storage to be located on APS’s AZ Sun sites.

This contract, with a 2023 in-service date, will complete the addition of storage on current APS-owned utility-scale solar facilities.

Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW.

These PPAs were subject to ACC approval in order to allow for cost recovery through the PSA.

APS received the requested ACC approval on January 12, 2021, and service under the agreements is expected to begin in 2022 with respect to 100 MW and in 2023 with respect to 50 MW.

As a result of its December 2020 RFPs, as of February 2022, APS has executed four 20-year PPAs for resources that include energy storage:

(a) two PPAs for standalone energy storage resources totaling 300 MW;

and (b) two PPAs totaling 275 MW solar plus storage resource.

The PPAs are also subject to ACC approval to enable cost recovery through the PSA.

APS received the requested ACC approval for three out of four of the projects on December 16, 2021.

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

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

APS currently plans to install more than 900 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above.

The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.

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

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

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

Energy Storage

PPAs - Energy Storage —

Residential Energy Storage 12(a) 3

Total Energy Storage Portfolio

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

Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of APS’s resource portfolio.

The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers.

Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States.

The plant’s continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.

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 MWh 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, a s a reliable, continuous, affordable resource and as a large contributor to the local economy.

We believe it is APS’s responsibility to deliver electric services to customers in the most cost-effective manner.

Since January 2018 through December 2020, the average residential bill decreased by 7.3%, or $10.95.

Since January 2018 through November 2021, the average residential bill decreased by 4.99%, or $7.48, 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, APS met its goal of $20 million in cost savings as of December 31, 2020.

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

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

APS is in discussions with the EIM operator, CAISO, and other EIM participants about the feasibility of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.

In 2021, APS continued to drive this initiative by identifying opportunities to streamline its business processes and deliver sustainable cost savings, which resulted in the Company identifying approximately $30 million in annual incremental cost saving opportunities in 2022.

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 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 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 and cost/benefit of creating a voluntary day-ahead market.

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

Notwithstanding the challenges presented by the COVID-19 pandemic as well as the hottest summer on record, APS continued to provide reliable service to its customers in 2020, setting a new all-time high peak energy demand of 7,660 MW, exceeding the prior peak set in 2017 by nearly 300 MW and achieved strong reliability results.

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.

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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.

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.

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.

In 2020, APS adopted a number of changes to improve customer experience.

It transitioned to a 24/7 care center operation to better serve its customers around the clock.

APS improved its call center performance, answering nearly 75% of its more than 1.5 million telephone calls in 30 seconds or less.

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

APS also convened a customer advisory board and stakeholder committee in 2020 to serve as a vehicle for gathering valuable qualitative insights, directly from customers and stakeholders, that intends to keep APS apprised of customer needs, wants, and perspectives.

Additionally, the customer advisory board is leveraged to identify and diagnose potential customer pain points and to help shape and co-create customer solutions.

APS is also providing assistance to residential and business customers that have been impacted by the COVID-19 pandemic.

See “COVID-19 Pandemic” above for more information about customer support during COVID-19.

Emerging Technologies

Energy Storage

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

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

Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset.

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

We are preparing for additional energy storage in the future.

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

Service under the agreement was scheduled to begin in 2021;

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

In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites.

Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site.

These battery storage facilities are expected to be in service by June 2022.

Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW.

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

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

These PPAs were also subject to ACC approval in order to allow for cost recovery through the PSA.

APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.

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

The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.

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

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

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

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

Recognizing that creating customer value is inextricably linked to increasing shareholder value, APS’s focus remains on its customers and the communities it serves.

Accordingly, it is APS’s goal to achieve an industry-leading, best-in-class customer experience.

This multi-year objective includes incrementally improving the company’s J.D.

Power (“JDP”) overall customer satisfaction ratings from the fourth quartile to the first quartile of its peer set comprised of large investor-owned utilities.

APS’s rating improved in 2021 with its fourth-quarter JDP residential overall customer satisfaction score ranked in the

third quartile.

APS made year-over-year improvements in power quality and reliability, billing and payment, and phone customer care.

In mid-2021, APS initiated an organization-wide customer experience strategy council designed to further drive a customer-oriented culture and improve JDP Company performance.

Through this and other on-going customer-centric initiatives, APS has embraced increased empathy training for care center associates and adopted more flexible payment arrangements for customers.

Numerous customer web-based enhancements also were implemented, including streamlined navigation and Spanish language transaction capabilities on aps.com;

an enhanced online power outage center;

and enrollment of more than 1 million customers for outage email and text notifications.

Furthermore, APS launched a broad-reaching ad campaign focused on energy efficiency and financial assistance programs.

APS offers discounts to qualified limited-income customers, as well as programs to help customers stay current on their bills.

Qualified customers experiencing an unplanned major expense or an unexpected reduction in income can receive up to $800 a year to cover current or past due APS bills through the Crisis Bill Assistance program.

APS’s Energy Support program gives qualified limited-income customers a 25% discount on their bill each month.

As of December 31, 2021, customers received almost $23 million in bill assistance from various sources, with the largest amount coming from the Arizona Department of Economic Security’s Emergency Rental Assistance Program.

This combined funding will aid approximately 36,000 APS customers.

A customer advisory board and a consumer working group were formed in 2020, one made up of a cross-section of customers, and the other of stakeholders and advocates representing various customer interests, met several times in 2021 to keep APS apprised of customer needs, wants and perspectives.

Their direct feedback helped facilitate improved analysis, education, and communication to customers about their rate plan options, rate names and related communications.

As of December 1, 2021, about 54% of APS customers are on their most economical plan.

The advisory board also helped inform an on-going redesign and enhancements to APS’s monthly bill based on additional customer feedback, research, and industry best practices.

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 2020, APS expanded its Take Charge AZ Pilot Program and installed 84 dual-plug Level 2 charging stations at business customer locations with more stations expected to be added through 2021.

In 2021, APS continued its expansion of its Take Charge AZ Pilot Program.

As of January 2022, APS had installed approximately 400 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 by the end of 2021 with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations.

These stations will be accessible through the Electrify America charging network.

In addition to the Level 2 charging stations, APS has begun construction of DC 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 is scheduled to be completed by March 2021 and submitted to the ACC for review and approval.

APS actively participated in developing this plan.

The ACC approved the plan in December 2021.

APS is currently working with stakeholders to develop a budget and implementation plan for ACC review.

Hydrogen Production

Palo Verde, in partnership with Idaho National Laboratory and two other utilities, has been chosen by the DOE’s Office of Nuclear Energy to participate in a hydrogen production project with the goal to improve the long-term economic competitiveness of the nuclear power industry.

The multi-phase project is planned for 2020 through 2023.

In the first phase, Idaho National Laboratory will perform a technical and economic assessment of using electricity generated at Palo Verde to produce hydrogen.

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

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 (“PNW Hydrogen”), a newly formed subsidiary of Pinnacle West, applied for DOE funding for a larger scale hydrogen production demonstration project using electricity sourced from Palo Verde.

On October 7, 2021, PNW Hydrogen was notified that DOE’s Office of Energy Efficiency & Renewable Energy and Office of Nuclear Energy had selected PNW Hydrogen’s application for an award of $20 million in federal funding to support the hydrogen production demonstration project, subject to negotiation and execution of a definitive Cooperative Agreement funding instrument between PNW Hydrogen and DOE.

Carbon Capture

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APS will continue to monitor this emerging technology.

Environmental, Social, and Governance ( “ ESG ” ) Practices

Pinnacle West has been integrating ESG practices into its core work for almost 30 years.

As a business strategy, we seek solutions that provide “shared value,” meaning solutions that address societal and environmental challenges in a way that also delivers business value.

Our commitment extends beyond implementing sustainability practices;

we are dedicated to working with our stakeholders to identify and address the sustainability issues that we are uniquely positioned to impact through our business.

In 2020, in support of our clean energy commitment and the growing focus on ESG within our organization, we increased our efforts by dedicating a new Sustainability Department at Pinnacle West to integrating ESG best practices into the everyday work of the Company.

As a first step, the Company engaged the Electric Power Research Institute (“EPRI”) and leveraged input from employees, large customers, limited-income advocates, economic development groups, environmental non-governmental organizations, leading sustainability academics and other stakeholders to identify and assess the sustainability issues that matter most.

In total, 23 Priority Sustainability Issues (“PSIs”) were identified and prioritized.

The most critical category, Integral Shared Value, includes four issues deemed most important and most able to be impacted by our actions:

clean energy, customer experience, energy access and reliability and safety and health.

These Integral PSIs provide the foundation for informing our strategic direction, creating a framework for incorporating best practices and driving enterprise-wide alignment and accountability.

In 2021, the Company engaged EPRI for the second phase of this work, focused on benchmarking best practices within these four Integral Shared Value PSIs.

We will utilize the benchmarking information to identify opportunities for further improvement in our ESG performance.

In 2021, the Company established a Social Issues Committee Framework.

The goal of the framework is to provide a process for considering emergent social issues, and for determining whether or how best to engage.

The committee’s responsibility is to determine, using a set of principles grounded in the APS Promise and the PSIs, whether engagement on specific emergent social issues is appropriate and, if so, how best to engage.

In 2021, the Company finalized an ESG Strategic Framework to guide our work.

The framework is based upon three foundational pillars:

ESG Policy Advocacy (we advocate for policy that supports our clean energy goals);

Driving Performance (improving our ESG performance in the most important areas, including our PSIs);

and effectively communicating and amplifying our ESG story to our various stakeholders, including investors, customers, employees and beyond.

The framework will guide and shape our ESG work moving forward.

Regulatory Overview

On October 31, 2019, APS filed an application with the ACC seeking an annual increase in retail base rates of $69 million.

This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4).

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 selective catalytic reduction ("SCR") project that was the subject of a separate proceeding, see “Four Corners 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 proposed total annual revenue increase in APS’s application is $184 million.

The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS’s application were:

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

• 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;

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• 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);

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

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

On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case.

The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project.

RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

• recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.

See Note 4 for a discussion of the 2017 Settlement Agreement;

• 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 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 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.

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, to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) the CCT plan related to the closure or future closure of coal-fired generation facilities of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.

The CCT plan includes the following proposed components:

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

The hearing began January 14, 2021.

Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC.

development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, which would primarily be funded by customers.

In 2021, APS committed an additional $900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant.

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.

On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021.

The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see “Four Corners SCR Cost Recovery” below for additional in formation), (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 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 and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation.

These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable

through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m.

Monday through Friday, excluding holidays.

The 2019 Rate Case ROO, as amended, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures.

On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended.

On November 24, 2021, APS filed with the ACC an application for rehearing of the 2019 Rate Case and the application was deemed denied on December 15, 2021, as the ACC did not act upon it.

On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity.

On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action.

APS cannot predict the outcome of this proceeding.

Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021.

On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m.

to 7 p.m., but did not explicitly approve the 10-months contemplated in APS’s verbal testimony to implement the new time-of-use hours.

On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022.

On January 12, 2022, the ACC voted to extend until September 1, 2022, the deadline to complete the implementation of the new on-peak hours for residential customers.

In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers.

APS cannot predict the outcome of this matter.

APS expects to file an application with the ACC for its next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.

See Note 4 for information regarding additional regulatory matters.

Arizona Attorney General Matter

APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement.

APS fully cooperated with the Attorney General’s Office in this matter.

On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter.

The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.

While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project.

On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031.

The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals.

APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance.

Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2021.

If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately $154.4 million.

We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved.

See Note 4 for additional information regarding the Four Corners SCR cost recovery.

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.

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

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

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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”).

and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms.

Clear Creek achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020.

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

Both wind farms deliver power under long-term PPAs.

BCE indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.

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

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

Additionally, El Dorado committed to a $25 million investment in invisionAZ Fund, which is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately held early stage and emerging growth technology companies and businesses primarily based in the State of Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in the State of Arizona.

Key Financial Drivers

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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.

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.

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For the three years through 2021, APS’s customer growth averaged 2.2% per year.

We currently project annual customer growth to be 1.5% to 2.5% for 2021 and for 2021 through 2023 based on our assessment of steady population growth in Arizona.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.4% for the year ended December 31, 2020 compared with the prior-year period.

While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong residential sales due to work-from-home policies and a gradual improvement in sales to commercial and industrial customers.

Though the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic.

From March 13, 2020 through December 31, 2020, the cumulative impact on weather-normalized usage was approximately a 1% increase.

APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat into 2021 as business activity continues to recover and more people return to work.

For the three years 2018 through 2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations.

We currently project that annual retail electricity sales in kWh will increase in the range of 0.5% to 1.5% for 2021 and increase on average in the range of 1.0% to 2.0% during 2021 through 2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations.

This projected sales growth range now includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers develop more usage history.

These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, or acceleration of the expected effects of customer conservation, energy efficiency, distributed renewable generation initiatives.

We currently project annual customer growth to be 1.5% to 2.5% for 2022, and the average annual growth will be in the range of 1.5% to 2.5% through 2024 based on anticipated steady population growth in Arizona during that period.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, for the year ended December 31, 2021, compared with the prior-year period increased 4.2%, which reflects a correction to 2020 commercial and industrial customer sales volumes of 111 GWh (“2020 Sales Volume Correction.”).

The 2020 Sales Volume Correction impacted prior disclosure in our Quarterly Reports on Form 10-Q.

The retail electricity sales in kWh, adjusted to exclude the effects of weather variations, for the three-month period ended March 31, 2021, the six-month period ended June 30, 2021, and the nine-month period ended Sept 30, 2021 with the 2020 Sales Volume Correction reflected would have been 0.2%, 3.1% and 3.5%, respectively.

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.

For the three years through 2021, annual retail electricity sales growth averaged 1.7%, adjusted to exclude the effects of weather variations.

We currently project that annual retail electricity sales in kWh will increase in the range of 1.5% to 2.5% for 2022, and 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 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 shift away from remote work, slower than expected commercial and industrial expansions, or acceleration of the expected effects of customer conservation, energy efficiency and distributed renewable generation initiatives.

Consistent with our focus on continuously looking for improvement in our processes and procedures, we updated our weather normalization methodology in 2020 to better leverage available AMI data (smart meter data).

While the prior method only used one to two months of daily usage data to estimate weather impacts, the new method utilizes a rolling four-year period of daily usage data, which improves the accuracy of estimated weather impacts on energy sales since many more data points are used for each calculation.

Our 1.4% weather normalized sales growth for the year ended December 31, 2020 reflects this change in methodology.

The impact to our 2019-2021 average normalized sales growth from this change in methodology is 0.1%.

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.

In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data.

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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.

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 DSM related expenses (which are offset by the same amount of operating revenues) and other factors.

Depreciation and Amortization Expenses.

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Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized.

(See Note 5 for details of the impacts on the Company as of December 31, 2020.) In APS’s 2017 Rate Case Decision, the ACC approved the TEAM, which is being used to pass through the income tax effects to retail customers of the Tax Act.

See Note 5 for details of the impacts on the Company as of December 31, 2021.

In APS’s 2017 Rate Case Decision, the ACC approved the TEAM, which was being used to pass through the income tax effects to retail customers of the Tax Act.

As part of the 2019 Rate Case (defined above), all impacts of the Tax Act were removed from the TEAM and incorporated into APS's base rates.

The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in APS’s next rate case.

See Note 4 for details of the TEAM.

Interest Expense.

Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 7).

Interest expense is affected by the amount of debt outstanding and the interest rates on that debt.

See Note 7 for further details.

The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.

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Our consolidated net income attributable to common shareholders for the year ended December 31, 2021, was $619 million, compared with $551 million for the prior year.

The results reflect an increase of approximately $13 million for the regulated electricity segment primarily due to higher revenue driven by the effects of weather and lower refunds in the current year related to the Tax Act, higher pension and other postretirement non-service credits and higher revenue from customer growth, partially offset by higher income taxes, including lower amortization of excess deferred taxes, higher depreciation and amortization expense, and higher other expenses.

Weather had a significant impact on our result of operations due to the hotter than normal weather in 2020 compared to 2019.

The results reflect an increase of approximately $69 million for the regulated electricity segment primarily due to higher revenue driven by higher customer usage and growth, lower refunds in the current year related to the Tax Act, higher transmission revenues, the one-time charge in 2020 related to the Arizona Attorney General Matter, higher pension and other postretirement non-service credits, and lower other expenses, partially offset by the effects of weather, higher depreciation and amortization expense and higher income taxes, including lower amortization of excess deferred taxes.

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

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Income taxes (Note 5)

(110) (78) (32)

Less income related to noncontrolling interests (Note 18)

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(dollars in millions)

Effects of weather

$ 165 $ 40 $ 125

Higher retail revenue due to changes in customer usage patterns and customer growth, partially offset by the impacts of energy efficiency and distributed generation $ 112 $ 36 $ 76

Lower refunds in the current year related to the Tax Act (Note 4)

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals

Lost fixed cost recovery

Lower renewable energy regulatory surcharges, offset by operations and maintenance costs (9) — (9)

Lower retail revenue due to the impacts of energy efficiency, distributed generation and changes in customer usage patterns, partially offset by higher customer growth (4) 6 (10)

Lower transmission revenues (Note 4)

Higher transmission revenues (Note 4)

Arizona Attorney General Matter (Note 11)

Higher renewable energy regulatory surcharges, offset by operations and maintenance costs 14 (5) 19

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 158 160 (2)

Effects of weather (150) (36) (114)

Miscellaneous items, net 1 4 (3)

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Operations and maintenance .

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

• An increase of $25 million primarily related to COVID Customer Support Fund, personal protective equipment and other health and safety-related costs for COVID-19 response (see Note 4);

Operations and maintenance expenses decreased $2 million for the year ended December 31, 2021, compared with the prior-year period primarily because of:

• A decrease of $21 million primarily related to the COVID Customer Support Fund (see Note 4), personal protective equipment and other health and safety-related costs for COVID-19 response;

• A decrease of $13 million for costs related to transmission and distribution;

• An increase of $16 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

• An increase of $12 million related to employee benefits;

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

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

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

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

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

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

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

• An increase of $4 million for corporate resources and other miscellaneous factors.

Depreciation and amortization.

Depreciation and amortization expenses were $23 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to increased plant in service of $37 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $17 million.

Depreciation and amortization expenses were $37 million higher for the year ended December 31, 2021, compared with the prior-year period primarily due to increased plant in service of $31 million and the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $6 million.

Taxes other than income taxes.

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Pension and other postretirement non-service credits, net.

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

Pension and other postretirement non-service credits, net were $57 million higher for the year ended December 31, 2021, compared to the prior-year period primarily due to actual market returns exceeding estimated returns in 2020.

All other income and expenses, net.

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

All other income and expenses, net were $35 million higher for the year ended December 31, 2021, compared to the prior-year period primarily due to the prior year CCT and APS Foundation contributions.

Interest charges, net of allowance for borrowed funds used during construction.

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

Interest charges, net of allowance for borrowed funds used during construction were $4 million higher for the year ended December 31, 2021, compared to the prior-year period primarily due to higher debt balances in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.

Income taxes.

Income taxes were $94 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to higher pre-tax net income and lower amortization of excess deferred taxes, partially offset by higher tax credits.

Income taxes were $32 million higher for the year ended December 31, 2021, compared with the prior-year period primarily due to higher pre-tax net income and lower amortization of excess deferred taxes, partially offset by a net operating loss carryback benefit that the Company recognized during the first quarter of 2021.

LIQUIDITY AND CAPITAL RESOURCES

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Net cash flow provided by financing activities 477 361

Net increase in cash and cash equivalents $ 50 $ 5

Net increase (decrease) in cash and cash equivalents $ (50) $ 50

Arizona Public Service Company

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Net cash flow provided by financing activities 478 404

Net increase in cash and cash equivalents $ 47 $ 4

Net increase (decrease) in cash and cash equivalents $ (48) $ 47

Operating Cash Flows

2021 Compared with 2020.

Pinnacle West’s consolidated net cash provided by operating activities was $967 million in 2020 compared to $957 million in 2019.

The increase of $10 million in net cash provided is primarily due to higher cash receipts from electric revenues, lower payments for operations and maintenance, lower pension contributions, lower customer advances for construction, lower income tax payments and lower other taxes, partially offset by higher fuel and purchased power costs.

The difference between APS and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West.

Pinnacle West’s consolidated net cash provided by operating activities was $860 million in 2021 compared to $967 million in 2020, a decrease of $107 million in net cash provided primarily due to $252 million higher fuel and purchased power costs, $93 million higher payments for operations and maintenance costs, $15 million higher other taxes and $11 million higher interest payments, partially offset by $175 million higher cash receipts from electric revenues and $93 million other changes in working capital.

The difference between APS and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West and 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.

Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries.

The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan.

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The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations.

Under ERISA, the qualified pension plan was 124% funded as of January 1, 2021 and 117% as of January 1, 2020.

Under accounting principles generally accepted in the United States of America ("GAAP"), the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, 2020.

(See Note 8 for additional details).

The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments.

Under ERISA, the qualified pension plan was estimated to be 138% funded as of January 1, 2022, and was 131% as of January 1, 2021.

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.

We made contributions to our pension plan totaling $100 million in 2021, $100 million in 2020, and $150 million in 2019.

The minimum required contributions for the pension plan are zero for the next three years.

We expect to make voluntary contributions up to $100 million in 2021 and zero thereafter.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019.

We do not expect to make

any contributions over the next three years to our other postretirement benefit plans.

The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2022, 2023 or 2024.

Regarding contributions to our other postretirement benefit plan, we did not make any contributions in 2021 or 2020 and do not expect to make any contributions in 2022, 2023 or 2024.

The Company was reimbursed $24 million in 2021, $26 million in 2020, and $30 million in 2019 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe, our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status.

For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, is still above 107% funded as of December 31, 2021, and our postretirement benefit plans have a funded status, also as measured for GAAP purposes at December 31, 2021, in excess of 145%.

See Note 8 for additional details.

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.

We paid approximately $9 million on December 28, 2021, and will pay the second half of this cash deferral by December 31, 2022.

Investing Cash Flows

2021 Compared with 2020.

Pinnacle West’s consolidated net cash used for investing activities was $1,278 million in 2020 compared to $1,131 million in 2019.

The increase of $147 million in net cash used primarily related to increased capital expenditures.

Pinnacle West’s consolidated net cash used for investing activities was $1,387 million in 2021 compared to $1,278 million in 2020, an increase of $109 million in net cash used primarily related to increased capital expenditures.

Capital Expenditures.

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The table above does not include capital expenditures related to BCE projects.

Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS.

Generation capital expenditures also include improvements to existing fossil plants.

Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and

environmental equipment.

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

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2021 Compared with 2020.

Pinnacle West’s consolidated net cash provided by financing activities was $361 million in 2020 compared to $179 million of net cash provided in 2019, an increase of $182 million in net cash provided.

The increase in net cash provided by financing activities includes $504 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $315 million, a net increase in short term borrowings of $16 million and higher dividend payments of $21 million.

APS’s consolidated net cash provided by financing activities was $404 million in 2020 compared to $133 million of net cash provided in 2019, an increase of $271 million in net cash provided.

The increase in net cash provided by financing activities includes lower long-term debt repayments of $135 million and $8 million in higher issuances of long-term debt, higher equity infusion of $150 million and higher dividend payments of $21 million.

Pinnacle West’s consolidated net cash provided by financing activities was $477 million in 2021 compared to $361 million of net cash provided in 2020, an increase of $116 million in net cash provided by financing activities primarily due to $915 million lower long-term debt

repayments, partially offset by $850 million in lower issuances of long-term debt, a net increase in short-term borrowings of $69 million and higher dividend payments of $19 million.

APS’s consolidated net cash provided by financing activities was $478 million in 2021 compared to $404 million in 2020, an increase of $74 million in net cash provided by financing activities primarily due to $465 million lower long-term debt repayments, offset by $653 million in lower issuances of long-term debt, a net increase in short-term borrowings of $279 million, and higher dividend payments of $19 million.

Significant Financing Activities.

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For the year ended December 31, 2021, Pinnacle West’s total dividends paid per share of common stock were $3.34 per share, which resulted in dividend payments of $369 million.

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

On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050.

The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.

On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025.

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

On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050.

The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.

On November 19, 2020, APS reopened its $300 million, 2.6% unsecured senior notes that mature on August 15, 2029, and issued an additional $105 million of 2.6% unsecured senior notes.

The aggregate balance of $405 million will mature on August 15, 2029.

The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $49.4 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.

On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022.

The proceeds were received on January 4, 2021 and used for general corporate purposes.

We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.

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

APS used this contribution to repay short-term indebtedness.

Available Credit Facilities .

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

On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021.

Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum.

At December 31, 2020, Pinnacle West had $19 million in outstanding borrowings under the agreement.

At December 31, 2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023.

Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings.

The facility is available to support Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits.

At December 31, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $150 million of commercial paper borrowings.

At December 31, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.

APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.

Interest rates are based on APS’s senior unsecured debt credit ratings.

These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.

At December 31, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding and no commercial paper borrowings.

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

See Note 6 for more information on available credit facilities.

Other Financing Matters.

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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).

See Note 7 for further discussions of liquidity matters.

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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.

On November 9, 2021, S&P downgraded the issuer ratings of the Company and APS from A- to BBB+.

S&P also downgraded the senior unsecured ratings of the Company and APS from BBB+ to BBB and A- to BBB+, respectively, with a negative outlook retained.

Commercial paper ratings remained unchanged at A-2 for both entities.

On November 17, 2021, Moody’s downgraded both the issuer and senior unsecured ratings of the Company from A3 to Baa1.

Concurrently, Moody’s downgraded the issuer and senior unsecured ratings of APS from A2 to A3.

Commercial paper for APS was downgraded from P-1 to P-2.

The commercial paper ratings for the Company remain unchanged.

The outlooks for both companies are negative.

At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.

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Pinnacle West

Corporate credit rating A3 A- A-

Senior unsecured A3 BBB+ A-

Corporate credit rating Baa1 BBB+ BBB+

Senior unsecured Baa1 BBB BBB+

Commercial paper P-2 A-2 F2

Outlook Negative Stable Negative

Corporate credit rating A2 A- A-

Senior unsecured A2 A- A

Outlook Negative Negative Negative

Corporate credit rating A3 BBB+ BBB+

Senior unsecured A3 BBB+ A-

Commercial paper P-2 A-2 F2

Outlook Negative Stable Negative

Off-Balance Sheet Arrangements

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

Outlook Negative Negative Negative

Contractual Obligations

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

2025 Thereafter Total

Long-term debt payments, including interest:

APS $ 227 $ 452 $ 985 $ 8,796 $ 10,460

Pinnacle West 7 14 510 — 531

Total long-term debt payments, including interest 234 466 1,495 8,796 10,991

Short-term debt payments, including interest (b) 169 — — — 169

Fuel and purchased power commitments (c) 657 1,243 1,134 5,264 8,298

Renewable energy credits (d) 35 61 53 105 254

Purchase obligations (e) 115 60 22 185 382

Coal reclamation 16 35 39 69 159

Nuclear decommissioning funding requirements 2 4 4 48 58

Noncontrolling interests (f) 23 46 32 127 228

Operating lease payments (g) 14 20 11 37 82

Total contractual commitments $ 1,265 $ 1,935 $ 2,790 $ 14,631 $ 20,621

(a) The long-term debt matures at various dates through 2050 and bears interest principally at fixed rates.

Interest on variable-rate long-term debt is determined by using average rates at December 31, 2020 (see Note 7).

(b) See Note 6 for further details.

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

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

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

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

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

This table excludes $46 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.

In January 2021, approximately $391 million of new fuel and purchased power commitments have been executed, primarily relating to periods after 2025 (see Note 9).

Estimated minimum required pension contributions are zero for 2021, 2022 and 2023 (see Note 8).

Pinnacle West has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs.

Material contractual obligations and other commitments are as follows:

• Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates.

Interest on variable-rate long-term debt is determined by using average rates at December 31, 2021.

• Pinnacle West and APS maintain committed revolving credit facilities.

See Note 6 for short-term debt details.

• Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation.

See Notes 4 and 11.

Purchase obligations includes capital expenditures and other obligations.

Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments.

• APS holds certain contracts to purchase renewable energy credits in compliance with the RES.

See Notes 4 and 11.

• APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation.

• APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033.

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.

Some of those judgments can be subjective and complex, and actual results could differ from those estimates.

We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

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Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.

This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.

This determination reflects the current political and regulatory climate in Arizona and is

subject to change in the future.

If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings.

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We review these assumptions on an annual basis and adjust them as necessary.

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

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2021, reported pension assets and liabilities on the Consolidated Balance Sheets and our 2021 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

Increase (Decrease)

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This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes.

The scenarios consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates.

The scenarios

consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates.

The fair value of an ARO is recognized in the period in which it is incurred.

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OTHER ACCOUNTING MATTERS

On January 1, 2020, we adopted ASU 2016-13, and related amendments, pertaining to the measurement of credit losses on financial instruments.

In 2020, we also adopted ASU 2018-14, related to defined benefit plan disclosures.

(See Note 3 for additional information related to new accounting standards.)

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.

We adopted the standard on January 1, 2022 using a prospective approach.

The adoption of this standard did not impact our financial statements.

See Note 3 for additional information.

MARKET AND CREDIT RISKS

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

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

Interest Rate and Equity Risk

35 unchanged sentences

APS — Consolidated

Variable-Rate

Debt Variable-Rate

Long-Term Debt Fixed-Rate

Long-Term Debt

Interest Interest

2020 Rates Amount Rates Amount

Interest Interest Interest

2021 Rates Amount Rates Amount Rates Amount

2022 0.18 % $ 279 — $ — — $ —

1 unchanged sentence

2024 — — — — 3.35 % 250

2025 — — — — 3.15 % 300

2026 — — — — 2.55 % 250

Years thereafter — — 0.22 % 36 3.87 % 5,480

8 unchanged sentences

2024 — — 3.35 % 250

2025 — — 3.15 % 300

Years thereafter 0.18 % 36 3.95 % 5,280

10 unchanged sentences

Mark-to-market of net positions at beginning of year $ (13) $ (71)

Decrease (Increase) in regulatory asset 57 (15)

Increase in regulatory liability 120 57

Recognized in OCI:

26 unchanged sentences

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

What changed 10-K

Item 7. Management’s Discussion and Analysis