What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-27 compared with 2022-02-25 · 309 added, 254 removed, 556 unchanged (50% of the section changed)

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APS is also the operator and co-owner of Palo Verde — a primary source of electricity for the southwest United States and the largest nuclear power plant in the United States.

COVID-19 Pandemic

The COVID-19 pandemic continues to be an evolving situation.

The Company is operating under long-standing pandemic and business continuity plans that exist to address situations including pandemics like COVID-19.

We are focused on ensuring the health and safety of our employees, contractors, and the general public by helping limit the spread of this virus and ensuring continued, safe, and reliable electric service for APS customers.

We identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue arose.

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

We also established COVID-19 safety protocols, social distancing practices and offering virtual options whenever possible.

The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic.

Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace.

As a result of these efforts, we were able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers, and communities.

In the summer of 2021, the Company began transitioning employees that were previously working remotely back to the workplace on a limited basis and began the reduction of our COVID-19 safety protocols and restrictions.

Due to the COVID-19 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.

Overall inflation has grown by 9.5% in Phoenix in 2022, compared to 6.5% nationally;

however, APS’s work with national and international companies has helped to partially reduce local cost escalation impacts on APS.

The impacts from inflation have varied across separate categories of APS’s spending.

Pricing increases across major categories have ranged from 8% to 10% for vendor services and up to 15% to 60% for equipment in 2022.

APS has seen specific inflationary impacts in individual spend categories, as well as general inflationary pricing impacts on a broader set of spend categories.

Some of the highest increases in 2022 as compared to 2021 have been in chemical costs and contract services.

Even prior to these increases, APS has focused on its customer affordability initiative, which has enabled APS to mitigate inflationary pressure.

This initiative includes identifying efficiency opportunities through APS’s LEAN Sigma approach as well as other corporate decisions.

For example, APS maintains its inventory to take advantage of lower pricing, when available, and to minimize supply chain delays that can increase the pricing due to expediting fees.

Additionally, APS has proactively entered into long-term contracts to hedge against price volatility, which has allowed it to mitigate several procurement spend areas such as transformers.

Inflation Reduction Act of 2022

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”).

The IRA significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage.

Key provisions that are relevant to the Company’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a Production Tax Credit (“PTC”) in lieu of the Investment Tax Credit (“ITC”) beginning in 2022;

(ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023;

and (iii) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032.

The Internal Revenue Service and U.S.

Treasury are expected to issue regulations and other guidance which will provide additional details and clarifications regarding how the Company may be able to claim each of these credits.

In addition, the IRA contains several provisions which could create additional tax liabilities for corporations, including a 15% corporate alternative minimum tax for corporations with net profits in excess of $1 billion and a 1% excise tax on stock buybacks.

We currently do not believe the Company will be subject to any material tax liabilities as a result of these legislative provisions.

COVID-19 continues to be an evolving situation.

Essential planned work and capital investments continued during the pandemic with priority given to support fire mitigation and summer storm efforts, as well as heat-related outages.

Raw material shortages, rising inflation, COVID-19 related work force disruptions and natural disasters continue to place increased pressure on the global supply chain.

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

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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.

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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.

The Coronavirus Aid, Relief, and Economic Security (“CARES”) Act allowed employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020, through December 31, 2020.

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

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 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.

As of December 31, 2022, we have paid this cash deferral in full .

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

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

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

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

Effective February 1, 2023, late payment fees for residential customers were reinstated, and late payment fees for commercial and industrial customers were reinstated effective May 1, 2022.

See Note 3 for additional information regarding the Summer Disconnection Moratorium.

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.

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

Strategic Overview

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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 all carbon-free resources like nuclear and demand-side management, and “ renewable ” is expressed as a percent of retail sales.

“Clean” is measured as percent of energy mix which includes all carbon-free resources like nuclear, renewables, and demand-side management.

“Renewable” energy includes generation sources such as solar, wind, and biomass, and is measured in accordance with the ACC’s Renewable Energy

Standard as a percentage of retail sales.

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

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

We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable projects.

Our proposed CCT plan supported the Navajo Nation, where Four Corners is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant.

We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable energy projects.

Our proposed CCT plan supported the Navajo Nation, where Four Corners is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which was impacted by closure of the Navajo Plant.

On November 2, 2021, the ACC approved an amended 2019 Rate Case ROO that will require (i) equal payments over a three-year period that total $10 million to the Navajo Nation, (ii) a $1 million one-time payment to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (iii) a $500,000 one-time payment to the Navajo County communities within 60 days of the 2019 Rate Case decision, (iv) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (v) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation.

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See Note 3 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.

Consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT:

(i) $3.33 million to the Navajo Nation;

(ii) $0.5 million to the Navajo County communities;

and (iii) $1 million to the Hopi Tribe.

Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments:

(i) $0.5 million to the Navajo Nation for CCT;

(ii) $1.1 million to the Navajo County Communities for CCT and economic development;

and (iii) $1.25 million to the Hopi Tribe for CCT and economic development.

The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation.

Expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations is contingent upon completion of a census of the unelectrified homes and businesses in each that are also within APS service territory.

On September 28, 2022, ACC Staff filed their staff report in the Matter of Impact of the Closures of Fossil-Based Generation Plan on Impacted Communities.

APS and other interested parties filed comments on the report.

On October 21, 2022, ACC Staff filed a revised report and proposed order.

The revised report and proposed order recommended that funds for CCT shall not be collected from rate payers.

On December 8, 2022, the ACC voted against ACC Staff’s proposed order.

APS cannot predict if the ACC will take any further action on this matter.

In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners beginning in fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership.

Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring.

The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages.

APS anticipates that it will elect not to begin seasonal operation in November 2023, unless market conditions change.

APS’s IRP (see Note 3 for additional information) establishes the path to meeting our clean energy commitment and maintaining reliable electric service for our customers.

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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 uses competitive “All-Source” RFPs to pursue market resources that meet its system needs and offer the best value for customers.

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

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(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.

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

As a result of the December 2020 RFPs, APS executed two solar plus storage PPAs totaling 275 combined MW, a PPA for a 238 MW wind resource, two energy storage PPAs for a combined 300 MW, extended an existing natural gas tolling agreement and also executed an engineering,

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

In May 2022, APS issued an RFP to address resource needs for 2025 and beyond.

The 2022 RFP solicits competitive proposals for approximately 1,000 MW to 1,500 MW of resources, including up to 600 MW to 800 MW of renewable resources to meet the needs of 2025 and 2026 while considering resources that can be online as late as 2027.

The 2022 RFP stopped accepting bids on July 15, 2022, and APS sent notifications to shortlisted bidders on September 23, 2022.

As a result of the 2022 RFP, and as of December 31, 2022, APS has signed a PPA for 300 MW of solar plus energy storage resources and a PPA for 216 MW of wind resources.

Once it secures those important resources and closes out the 2022 RFP, APS intends to issue its next RFP to address future resource needs.

Energy Storage .

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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.

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

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

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

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

These battery storage facilities are currently expected to be in service during the first quarter of 2023.

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

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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:

APS received the requested ACC approval on January 12, 2021, and service under the agreements is expected to begin in 2023.

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

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

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

and (b) two PPAs for solar plus energy storage resources totaling 275 MW.

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

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

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

APS received the requested ACC approval for three out of four of the projects on December 16, 2021 and on April 13, 2022 for the remaining project.

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

Following the 2022 RFP, as of January 2023, APS has executed a 20-year PPA for solar plus storage resources totaling 300 MW.

The PPA is subject to ACC approval to enable cost recovery through the PSA, which was requested in December 2022 and approved in February 2023.

Service under this agreement is expected to begin in 2025.

APS currently plans to install more than 1,200 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above.

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Development (MW)

Energy Storage

APS Owned Energy Storage

PPAs Energy Storage —

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(a) This includes 18.5 MW of APS customer-owned batteries and 0.2 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, the nation’s la rgest carbon-free, clean energy resource, will continue to be a foundational part of APS’s resource portfolio.

Palo Verde is not just the cornerstone of our current clean energy mix;

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 November 2021, the average residential bill decreased by 4.99%, or $7.48, due to net reductions in cost recovery adjustor mechanisms.

The plant is a critical asset to the Southwest, generating more than 32 million MWh annually – enough power for roughly 3.4 million households, or approximately 8.5 million people.

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

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.

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.

The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and achieving internal efficiencies.

APS continues to drive this initiative by identifying opportunities to streamline its business processes to assist in mitigating cost increases, increasing employee retention, and improving customer satisfaction.

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

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

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

APS is managing through significant growth in the Phoenix metropolitan area while experiencing supply chain issues similar to other industries.

Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth, and enabling more renewable energy resources.

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Wildfire safety remains a critical focus for APS and other utilities.

We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government entities and first responders and educate customers and communities.

We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, continue ongoing system upgrades, build partnerships with government entities and first responders and educate customers and communities.

These programs contribute to customer reliability, responsible forest management and safe communities.

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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 continues to evaluate options to meet growing energy demand and ensure grid reliability, including through upgrades to and/or modernization of additional existing gas facilities.

In October of 2021, APS announced plans to evaluate regional market solutions as part of the informal Western Markets Exploratory Group (“WMEG”).

As part of WMEG, APS is exploring the potential for a staged approach to new market services, including day-ahead energy sales, transmission system expansion, and other power supply and grid solutions consistent with existing state regulations.

WMEG hopes to identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers.

APS is unable to predict the outcome of these discussions.

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.

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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.

Accordingly, it is APS’s goal to achieve an industry-leading, best-in-class customer experience, while demonstrating compassion and advocacy for its customers.

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

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

APS’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.

APS made progress on that front in 2022.

As previously disclosed, APS’s JDP Residential rankings for overall customer satisfaction rating improved in 2020 and 2021.

That improvement trend continued with the JDP Residential 2022 year-end results.

Compared to 2021, APS made quartile gains in every single driver of residential customer satisfaction, firmly lifting APS into the second quartile nationally.

Consequently, overall residential satisfaction is now above industry benchmarks when compared to APS’s large investor-owned peers.

APS’s strongest performing drivers for the year were Customer Care (phone and digital), Power Quality and Reliability, Corporate Citizenship, and Billing & Payment.

Additionally, the JDP Business 2022 full-year results place APS in the top – or first – quartile of utilities nationally for business customers.

result, APS is among the most improved utilities in the nation for both residential and business customer satisfaction.

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

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

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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.

Additionally, APS launched a broad-reaching multi-channel communications campaign focused on messages that matter most to APS’s customers – reliability, energy-efficiency, financial assistance, the environment, and programs that enable customers to design their own personalized energy experience.

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

And, to ensure our most vulnerable customers are connected to these programs, we train and work with more than 100 community action agencies.

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

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.

Additionally, 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.

Making customers aware of the assistance programs and resources available to them is a top priority for APS, and we have significantly increased the level of marketing and customer outreach through various campaigns and communication channels.

As of December 31, 2022, approximately 60,000 customers received an aggregate of about $29.6 million in bill assistance from various sources, with the largest amount coming from the Arizona Department of Economic Security’s Emergency Rental Assistance Program.

This assistance is on top of the approximately $33 million of discounts provided to eligible customers through the APS Energy Support Program.

A consumer working group and a customer advisory board were formed in 2020 – the former made up of stakeholders and advocates representing various customer interests, and the latter comprised of a cross-section of customers.

APS meets monthly with the consumer working group to obtain feedback on customer-related initiatives.

Topics in 2022 ranged from TOU implementation, bill redesign, aps.com, customer assistance and customer care center performance.

APS also met with the customer advisory board in 2022 to keep apprised of customer needs, wants and perspectives on a variety of topics, including rate plan selection, billing and payment alerts, value for price insights and outage experience.

The customer advisory board’s input helped shape customer communications, as well as our thinking on related program development.

In September 2022, APS completed the transition to new 4 p.m.

on-peak TOU hours.

More than one million residential customer meters were reprogrammed to the new on-peak hours.

Developing Clean Energy Technologies

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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 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.

As of December 31, 2022, APS had installed 668 Level 2 (“L2”) charging ports at customer locations, with more stations expected to be added through 2023.

The program provides

charging equipment, installation, and maintenance to business customers, government agencies, non-profits, and multifamily housing communities.

In addition to the L2 charging stations, APS has deployed DC fast charging (“DCFC”) stations that are owned and operated by APS at five locations in Arizona.

The first location opened for public use in March 2022 in Show Low, Arizona.

The other four projects in Sedona, Prescott, Globe, and Payson were energized by the end of 2022.

Each location features 2-150 kilowatt and 2-350 kilowatt DCFC ports.

Charging at these stations will be accessible through the Electrify America charging network.

APS 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 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.

APS has a goal to reach 450,000 light-duty electric vehicles in its service territory by 2030.

Additionally, as part of APS’s DSM Plan, APS has launched an Electric Vehicle Charging Demand Management Pilot Program to proactively address the growing electric demand from electric vehicle charging as electric vehicles become more widely adopted.

This program includes the APS SmartCharge data gathering program, a $250 residential electric vehicle smart charger rebate for qualifying electric vehicle chargers, Fleet Advisory Services, and a $100 rebate to home builders for new homes to be built EV ready with 240V charging station garage outlets.

APS filed its 2023 DSM Plan on November 30, 2022, which proposes two new programs, an expanded residential EV Managed Charging Program and a Commercial Make-Ready Program.

The Commercial Make-Ready Program is intended to help reduce some of the high upfront cost for our customers installing DCFC stations, and enables APS to deploy effective load management strategies at these commercial sites.

The ACC ordered certain public service corporations, including APS, to develop a long-term, comprehensive statewide transportation electrification plan (“TE Plan”) for Arizona.

The statewide TE Plan is intended to provide a roadmap for transportation electrification in Arizona, focused on realizing the associated air quality and economic development benefits for all residents in the state along with understanding the impact of electric vehicle charging on the grid.

APS actively participated in the development of that plan, which was approved by the ACC in December 2021.

In the decision, the ACC also ordered APS and another large Arizona electric public service corporation to each develop and submit for ACC approval their own TE Plans and corresponding budget for 2023.

Accordingly, APS met its compliance obligation and filed both a 2023 TE Plan on June 1, 2022 and a supplemental TE Plan on November 30, 2022.

APS will file its required TE progress reports on March 15 and September 15, 2023, along with a 2024 TE Plan later this year.

Hydrogen Production

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.

APS, 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.

negotiation and execution of a definitive Cooperative Agreement funding instrument between PNW Hydrogen and DOE.

PNW Hydrogen continues to work through negotiations with DOE, while also investigating how best to coordinate its efforts with the Southwest Clean Hydrogen Innovation Network (“SHINe”) regional hub on development opportunities.

SHINe Regional Hub .

The Infrastructure Investment and Jobs Act (“IIJA”), also known as the Bipartisan Infrastructure Bill, was signed into law on November 15, 2021.

Among other things, the IIJA included money for regional clean hydrogen hubs, and on February 15, 2022, the Department of Energy DOE announced a Request for Information to collect feedback from stakeholders to inform the implementation and design of the regional hubs.

On May 12, 2022, APS, along with three other Arizona energy providers and the State’s three public universities announced the formation of a new, interdisciplinary coalition, called the Arizona Center for a Carbon Neutral Economy (“AzCaNE”), with the goal of attaining a carbon neutral economy in Arizona.

AzCaNE’s first action was to pursue the creation of an Arizona-led approach to securing regional clean hydrogen hub funding.

Leading professionals from the seven founding participants, along with representatives of Arizona, the Navajo Nation and companies working to develop a hydrogen ecosystem within Arizona make up the Governance Committee for AzCaNE’s current efforts.

On September 22, 2022, the DOE opened applications for the up to $7 billion program to create six to ten regional clean hydrogen hubs across the country.

Concept papers for each regional hub were due by November 7, 2022, and AzCaNE submitted a concept paper for the SHINe regional hub.

On December 27, 2022, the SHINe regional hub was one of thirty-three regional hubs encouraged to submit a full application by the DOE.

Full applications are due by April 7, 2023.

Carbon Capture

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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.

identify and assess the sustainability issues that matter most.

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

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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.

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

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

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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 Company also finalized an ESG Strategic Framework to guide our work.

The framework is based upon three foundational pillars:

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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.

Throughout 2022, the ESG Strategic Framework has guided our ESG activities allowing the Sustainability Department to prioritize projects and collaborate with our teams in the Company.

Also in 2022, the Company developed an ESG Narrative, aligned to the APS Promise, to guide the Company’s communications strategy internally and externally to customers to effectively share APS’s sustainability story.

Regulatory Overview

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 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:

2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates on the date rates become effective (“Day 1”) of a net $460 million.

This Day 1 net impact represents a total base revenue deficiency of $772 million offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications.

The average annual customer bill impact of APS’s request on Day 1 is an increase of 13.6%.

The principal provisions of APS’s application are:

• a test year comprised of 12 months ended June 30, 2022, adjusted as described below;

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

• a Base Fuel Rate of $0.030168 per kWh;

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

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

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

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

▪ a flat bill/subscription rate pilot program;

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

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

See Note 4 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 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 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.

• a rate of $0.038321 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs;

• modification of its adjustment mechanisms including:

▪ eliminate the Environmental Improvement Surcharge and collect costs through base rates,

▪ eliminate the Lost Fixed Cost Recovery mechanism and collect costs through base rates and the Demand Side Management Adjustment Charge (“DSMAC”),

▪ maintain as inactive the Tax Expense Adjustor Mechanism,

▪ maintain the Transmission Cost Adjustment mechanism,

▪ modify the performance incentive in the DSMAC, and

▪ modify the Renewable Energy Adjustment Charge to include recovery of capital carrying costs of APS owned renewable and storage resources;

• changes to its limited-income program, including a second tier to provide an additional discount for customers with greater need;

• twelve months of post-test year plant to reflect used and useful projects that will be placed into service prior to July 1, 2023.

APS requested that the increase become effective December 1, 2023.

The hearing for this rate case is currently scheduled to begin in August 2023.

APS cannot predict the outcome of its request.

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) seeking an increase in annual retail base rates.

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

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.

See Note 3 for information regarding the 2019 Rate Case ROO.

On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to 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.

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

(a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation, and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation.

These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m.

Monday through Friday, excluding holidays.

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

Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity.

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

The Arizona Court of Appeals heard oral arguments on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

APS cannot predict the outcome of 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.

APS completed the implementation of the new on-peak hours for residential customers before the September 1, 2022 deadline.

APS cannot predict if the ACC will take any further action on this matter.

Additionally, consistent with the 2019 Rate Case decision, as of April 2022, APS has completed the following payments that will be recoverable through rates related to the CCT:

(i) $3.33 million to the Navajo Nation;

(ii) $0.5 million to the Navajo County communities;

and (iii) $1 million to the Hopi Tribe.

Consistent with APS’s commitment to the impacted communities, APS has also completed the following payments:

(i) $0.5 million to the Navajo Nation for CCT;

(ii) $1.1 million to the Navajo County Communities for CCT and economic development;

and (iii) $1.25 million to the Hopi Tribe for CCT and economic development.

The ACC has also authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservation.

See Note 3 for information regarding additional regulatory matters.

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

The Arizona Court of Appeals heard oral arguments on November 30, 2022.

The Court took the matter under advisement and will issue its decision in due course.

Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2022.

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BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry.

As of December 31, 2022, BCE had total assets of approximately $115.3 million.

In 2014, BCE formed a 50/50 joint venture with BHE U.S.

Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company.

The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.

The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 U.S.

states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.

On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska Energy, Inc.

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

Tenaska Clear Creek Wind, LLC, the developer, owner, and operator of the Clear Creek wind farm, has disputed the proposed cost allocation of system upgrades related to connecting the Clear Creek wind farm to the transmission system and filed a complaint with FERC on May 21, 2021, which was denied on September 9, 2022.

Subsequently, Tenaska Clear Creek Wind, LLC filed with FERC a request for rehearing and a motion for stay of the September 9, 2022 order.

On October 7, 2022, the request for rehearing was denied by FERC.

FERC has not ruled on the motion for stay.

Clear Creek has filed a Petition for Review with the U.S.

Court of Appeals and Motion for Stay Pending Appeal, both of which are still pending.

Tenaska Clear Creek Wind, LLC filed a second complaint with FERC on May 25, 2022, alleging that the wind farm was being curtailed in a discriminatory manner.

The May 25, 2022 Complaint was denied by FERC on December 15, 2022 and Tenaska Clear Creek Wind, LLC requested Rehearing of the denial on January 13, 2023.

Due to the disputed system upgrades and the related curtailment, the Clear Creek wind farm has experienced a significant reduction in power generation that has had a material adverse impact on the project’s ability to generate cash flow for investors.

These energy curtailments are expected to persist, unless and until system upgrades are implemented to alleviate the present transmission system congestion, or the disputes are determined in favor of, or settled in a manner favorable to, Tenaska Clear Creek Wind, LLC.

As such, during the fourth quarter of 2022, due to these on-going disputes, cost allocation uncertainties, and no probable favorable resolution, BCE determined its equity method investment was fully impaired.

Prior to the impairment, the investment had a carrying value of $17.1 million, which has been written-down to reflect the investment’s estimated fair value of zero as of December 31, 2022.

Pinnacle West’s Consolidated Statement of Income for the year ended December 31, 2022 includes an after-tax loss of $12.8 million relating to this impairment.

BCE has started construction on a microgrid facility in Los Alamitos, California featuring 31 MW of solar, 20 MW of battery storage, and 3 MW of backup generators.

Supported by a long-term power purchase agreement with San Diego Gas and Electric Company, Los Alamitos will supply 20 MW of solar and battery storage capacity to the Southern California grid and provide resilient backup power in the event of a grid emergency to the Army and California National Guard at Joint Forces Training Base Los Alamitos.

The Los Alamitos project is scheduled to achieve commercial operation in third-quarter 2023.

See Note 6 regarding a credit agreement entered into by BCE to finance capital expenditures and related costs for this microgrid project.

BCE and Ameresco, Inc.

jointly own a special purpose entity that is sponsoring the Kūpono Solar project.

This project is a 42 MW solar and battery storage facility in Oʻahu, Hawaii that will supply clean renewable energy and capacity under a 20-year power purchase agreement with Hawaiian Electric Company, Inc.

The Kūpono Solar project is expected to be completed in 2024.

El Dorado is a wholly-owned subsidiary of Pinnacle West.

El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures.

El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.

In particular, El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.

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

As of December 31, 2022, El Dorado has contributed approximately $12.5 million to the Energy Impact Partners fund.

Additionally, El Dorado committed to a $25 million investment in 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.

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

As of December 31, 2022, El Dorado has contributed approximately $2.6 million to AZ-VC.

The remainder of the investment will be contributed by El Dorado as investments are selected by AZ-VC.

Key Financial Drivers

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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 2022, APS’s customer growth averaged 2.2% per year.

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.

We currently project annual customer growth to be 1.5% to 2.5% for 2023 and the average annual growth to be in the range of 1.5% to 2.5% through 2025 based on anticipated steady population growth in Arizona during that period.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 2.4% for the year ended December 31, 2022, 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 a strong improvement in sales to commercial and industrial customers and the ramp-up of new data center customers.

For the three years through 2022, annual retail electricity sales growth averaged 2.5%, 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.

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 DG, and responses to retail price changes.

Due to the expected rapid growth of several large data centers and new large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 3.5% to 5.5% for 2023 and that average annual growth will be in the range of 4.5% to 6.5% through 2025, 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 several large data centers and new large manufacturing facilities, which are expected to contribute to average annual growth in the range of 3.5% to 5.5% through 2025.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, slower ramp-up of and/or fewer data centers and large manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs, and growth in DG, and responses to retail price changes.

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

Historically, extreme weather variations have resulted in annual variations in net income in excess of $25 million.

However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.

Our experience indicates that typical variations from normal weather can result in increases and decreases in annual net income of up to $15 million;

however, extreme weather variations have resulted in larger annual variations in net income.

Fuel and Purchased Power Costs.

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The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.2% of the assessed value for 2022, 10.7% for 2021 and 10.8% for 2020.

We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities.

Property taxes decreased in 2022 due to recent legislative changes reducing both property tax assessment ratios and rates in Arizona.

As we add new generating units and continue with improvements and expansions to our existing generation, transmission, and distribution facilities in future years, we anticipate property taxes may increase, though these increases will continue to be partially offset by the impacts of the recent legislative changes noted above.

Income Taxes .

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Our consolidated net income attributable to common shareholders for the year ended December 31, 2022, was $484 million, compared with $619 million for the prior year.

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 results reflect a decrease of approximately $114 million for the regulated electricity segment, which include higher depreciation and amortization expense primarily due to the absence of the Ocotillo modernization project and the Four Corners SCR project regulatory deferrals that ended upon the 2019 Rate Case effective date (see Note 3), increased plant assets and updated depreciation rates.

In addition, the results reflect lower revenue driven by the LFCR alternative revenue treatment and higher operations and maintenance expense.

These negative factors were partially offset by higher revenue driven by the effects of weather, customer usage and growth, increased transmission revenue and lower income taxes.

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

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(dollars in millions)

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 3)

$ 141 $ — $ 141

Effects of weather 77 19 58

Higher retail revenue due to changes in customer usage patterns and customer growth, partially offset by the impacts of energy efficiency and distributed generation 46 23 23

Higher transmission revenues (Note 3)

Arizona Attorney General Matter (Note 11)

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

Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs 18 9 9

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 425 426 (1)

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

Lost fixed cost recovery (Note 3)

Impact of new retail base rates from 2019 Rate Case effective December 1, 2021 (147) — (147)

Miscellaneous items, net 2 — 2

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Operations and maintenance .

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;

Operations and maintenance expenses increased $32 million for the year ended December 31, 2022, compared with the prior-year period primarily because of:

• an increase of $14 million primarily related to a decreased recovery from contributions of administrative and general costs from Palo Verde owners and increased operating costs;

• an increase of $10 million primarily related to strategic planning consulting costs;

• an increase of $6 million for costs related to transmission, distribution and customer service;

• an increase of $6 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;

• a decrease of $12 million in non-nuclear generation costs primarily due to lower planned outages and partially offset by higher operating costs;

• an increase of $8 million for corporate resources and other miscellaneous factors.

Depreciation and amortization.

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.

Depreciation and amortization expenses were $102 million higher for the year ended December 31, 2022, compared with the prior-year period primarily due to $55 million for the Ocotillo modernization project and the Four Corners SCR project regulatory deferrals recorded in the prior year period that ended upon the 2019 Rate Case effective date and the related 2022 regulatory deferral amortization, and $47 million related to increased plant in service and updated depreciation rates.

Taxes other than income taxes.

Taxes other than income taxes were $10 million higher for the year ended December 31, 2021, compared with the prior-year period primarily due to higher property values.

Taxes other than income taxes were $15 million lower for the year ended December 31, 2022, compared with the prior-year period primarily due to the impacts of recent legislative changes reducing both property tax assessment ratios and rates in Arizona and property tax deferrals that ended upon the 2019 Rate Case effective date and the related 2022 property tax deferral amortization.

Pension and other postretirement non-service credits, net.

Pension and other postretirement non-service credits, net were $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.

Pension and other postretirement non-service credits, net were $15 million lower for the year ended December 31, 2022, compared to the prior-year period primarily due to actual market returns being lower than estimated returns in 2021.

All other income and expenses, net.

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.

All other income and expenses, net were $38 million lower for the year ended December 31, 2022, compared to the prior-year period primarily due to the Ocotillo modernization and Four Corners SCR debt deferrals that ended upon the 2019 Rate Case effective date.

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

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.

Interest charges, net of allowance for borrowed funds used during construction were $22 million higher for the year ended December 31, 2022, compared to the prior-year period primarily due to higher debt balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.

Income taxes.

Income taxes were $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.

Income taxes were $35 million lower for the year ended December 31, 2022, compared with the prior-year period primarily due to lower pre-tax net income, partially offset by a net operating loss carryback benefit that the Company recognized during the first quarter of 2021.

All other earnings were $21 million lower for year ended December 31, 2022, compared with the prior-year period primarily due to the Clear Creek wind farm impairment write-off.

See “BCE Matters” in Note 10 for additional details.

LIQUIDITY AND CAPITAL RESOURCES

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Net cash flow provided by financing activities 371 477

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

Net decrease in cash and cash equivalents $ (5) $ (50)

Arizona Public Service Company

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Net cash flow provided by financing activities 314 478

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

Net decrease in cash and cash equivalents $ (5) $ (48)

Operating Cash Flows

2022 Compared with 2021.

Pinnacle West’s consolidated net cash provided by operating activities was $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.

Pinnacle West’s consolidated net cash provided by operating activities was $1,242 million in 2022 compared to $860 million in 2021, an increase of $382 million in net cash provided primarily due to $542 million higher cash receipts from electric revenues, $47 million lower payments for operations and maintenance costs, $100 million lower pension contributions and $79 million other changes in working capital, partially offset by $321 million higher fuel and purchased power costs, $47 million higher income taxes and $18 million higher interest payments.

The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West in 2021.

Retirement plans and other postretirement benefits.

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We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount.

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

Under ERISA, the qualified pension plan was estimated to be 112% funded as of January 1, 2023, and was 139% as of January 1, 2022.

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The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2023, 2024 or 2025.

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

Regarding contributions to our other postretirement benefit

plan, we did not make any contributions in 2022 or 2021 and do not expect to make any contributions in 2023, 2024 or 2025.

The Company was reimbursed $26 million in 2022, $24 million in 2021, and $26 million in 2020 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

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

For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, 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%.

For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 106% funded as of December 31, 2022, and our postretirement benefit plans were 159% funded, as measured for GAAP purposes at December 31, 2022.

See Note 7 for additional details.

The CARES Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020, through December 31, 2020.

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

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

As of December 31, 2022, we have paid this cash deferral in full.

Investing Cash Flows

2022 Compared with 2021.

Pinnacle West’s consolidated net cash used for investing activities was $1,387 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.

Pinnacle West’s consolidated net cash used for investing activities was $1,618 million in 2022 compared to $1,387 million in 2021, an increase of $231 million in net cash used primarily related to increased capital expenditures and BCE investment activity.

Capital Expenditures.

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2022 Compared with 2021.

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.

Pinnacle West’s consolidated net cash provided by financing activities was $371 million in 2022 compared to $477 million 2021, a decrease of $106 million in net cash provided primarily due to $150 million higher long-term debt repayments, a net decrease in short-term borrowings of $74 million and higher dividend payments of $9 million, partially offset by $129 million in higher issuances of long-term debt.

APS’s consolidated net cash provided by financing activities was $314 million in 2022 compared to $478 million in 2021, a decrease of $164 million in net cash provided primarily due to a net decrease in short-term borrowings of $232 million and higher dividend payments of $9 million, partially offset by $78 million in higher issuances of long-term debt.

Significant Financing Activities.

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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).

On December 15, 2022, the ACC issued a financing order approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term debt for purposes of the ACC financing orders.

See Note 6 for further discussions of liquidity matters.

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The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained.

There is no assurance that these ratings will continue for any given period of time.

There is no assurance that these ratings will continue for any given period.

The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.

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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.

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

Moody’s Standard & Poor’s Fitch

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See Notes 3 and 10.

Purchase obligations includes capital expenditures and other obligations.

Purchase obligations include capital expenditures and other obligations.

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

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See Notes 3 and 10.

• 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.

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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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Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position.

The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, and the assumed healthcare cost trend rates.

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

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 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):

The most relevant actuarial assumptions are the discount rate, the expected long-term rate of return on plan assets (“EROA”), and the assumed healthcare cost trend rates.

Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense.

To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years.

Following are the most relevant actuarial assumptions:

Discount Rate.

The discount rate is used to measure the plan liability and net periodic cost.

For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future benefit payments to estimate the projected benefit obligation for each plan.

This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year’s benefit payments by a spot rate to that year.

The spot rates are derived from a yield curve composed of domestic AA rated corporate bonds.

The EROA is used to estimate earnings on invested funds over the long-term.

For this assumption we consider historical experience and future expectations of asset classes utilized in the portfolio.

Healthcare Cost Trend Rates.

We consider past performance and forecasts of health care costs and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022 reported pension assets and liabilities on the Consolidated Balance Sheets and our 2022 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions):

Increase (Decrease)

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Plans Impact on

Discount rate:

Discount rate (b):

Increase 1% $ (238) $ 3

Decrease 1% 279 13

Expected long-term rate of return on plan assets:

Increase 1% — (27)

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

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

(b) In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate.

Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment.

Therefore, the discount rate sensitivities above cannot necessarily be extrapolated.

Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the obligation and expense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2022, other postretirement benefit obligation on the Pinnacle West’s Consolidated Balance Sheets and our 2022 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

Increase (Decrease)

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Postretirement

Plans Impact on Other

Benefit Plans Impact on Other

Postretirement

Benefit Expense

Discount rate:

Discount rate (b):

Increase 1% $ (39) $ (3)

Decrease 1% 46 4

Healthcare cost trend rate (b):

Healthcare cost trend rate (c):

Increase 1% 43 8

Decrease 1% (36) (6)

Expected long-term rate of return on plan assets – pretax:

EROA – pretax:

Increase 1% — (7)

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

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

(b) In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate.

Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment.

Therefore, the discount rate sensitivities above cannot necessarily be extrapolated.

See Note 7 for further details about our pension and other postretirement benefit plans.

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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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AROs as of December 31, 2022 are described further in Note 11.

OTHER ACCOUNTING MATTERS

In July 2021, a new accounting standard, ASU 2021-05, was issued that amends lessor’s accounting treatment for certain lease transactions with variable lease payments.

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, 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 trusts, other special use funds and benefit plan assets.

Interest Rate and Equity Risk

We have exposure to changing interest rates.

Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Note 13 and Note 19), and benefit plan assets.

The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.

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Fair value $ 325 $ 163 $ 5,466

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 — $ — — $ —

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2024 — — — — 3.35 % 250

2025 — — — — 3.15 % 300

2026 — — — — 2.55 % 250

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

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The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

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

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

December 31, 2022 December 31, 2021

Mark-to-market of net positions at beginning of year $ 107 $ (13)

Increase in regulatory liability 120 57

Recognized in OCI:

Mark-to-market losses realized during the period — 1

Change in valuation techniques — —

Increase (decrease) in regulatory liability (11) 120

Mark-to-market of net positions at end of year $ 96 $ 107

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2021, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 2022, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.

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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