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Item 7. Management’s Discussion and Analysis

2024-02-27 compared with 2023-02-27 · 335 added, 409 removed, 456 unchanged (62% of the section changed)

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OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report.

The following discussion should be read in conjunction with Pinnacle West’s Consolidated

Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report.

This discussion provides a comparison of the 2023 results with 2022 results.

A comparison of the 2021 results with 2020 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, 2021.

For the discussion of 2022 compared to 2021, see Part II.

Management’s Discussion and Analysis of Financial Condition and Results of Operations of Pinnacle West Capital Corporation’s Annual Report on Form 10-K for the year ended December 31, 2022, which specific discussion is incorporated herein by reference.

For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $23 billion.

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $25 billion.

For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

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APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.4 million retail customers in 11 of Arizona’s 15 counties.

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

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.

APS is also the operator and co-owner of Palo Verde — a primary source of electricity for the southwestern United States.

Inflation Reduction Act of 2022

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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;

Key provisions that are relevant to APS’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.

and (iii) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants (“Nuclear PTC”), 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.

Treasury have issued preliminary guidance related to various provisions of the IRA that have enabled APS to claim credits related to its 2023 solar and battery investments.

The Company continues to await regulations and other guidance, including with respect to the Nuclear PTC, which will provide additional details and clarifications regarding how the Company may be able to claim IRA tax credits in future years.

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.

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

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

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

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

See Note 3 for additional information on the PSA.

APS has measures in place to continually monitor and evaluate resource needs and supply chain adequacy but cannot predict whether there will be material supply chain shortages in the future.

While the total expected impact of COVID-19 on future sales is currently unknown, APS experienced higher electric residential sales and lower electric commercial and industrial sales from the outset of the pandemic through April 2021.

Beginning in May 2021, electric sales from commercial and industrial customers increased to levels in line with pre-COVID-19 sales but residential sales continued to be higher than pre-COVID-19 sales.

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

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

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

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

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

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

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

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

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

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

Strategic Overview

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

Our strategy is to create a sustainable energy future for Arizona that delivers shareholder value and shared value by serving our customers with reliable, affordable, and clean energy.

Customer-Focused

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

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 to achieve a first quartile ranking in its peer set comprised of large investor-owned utilities.

APS has made noteworthy progress on that front.

As previously disclosed, APS’s JDP Residential rankings for overall customer satisfaction improved in each of 2020, 2021, and 2022, and have improved again in 2023.

At the end of 2023, APS’s residential customer satisfaction ranked in the second quartile among large investor-owned utilities, and its business customer satisfaction ranked in the second quartile of utilities nationally.

While our energy mix evolves, APS’s obligation to deliver reliable service to our customers remains.

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.

To prioritize reliability and meet substantial growth in residential and commercial energy needs, APS has developed a future-focused, strategic transmission plan.

This Ten-Year Plan includes five critical transmission projects that comprise the APS strategic transmission portfolio, which represents a significant upgrade to APS’s transmission system.

These five projects, along with other projects included in the Ten-Year Plan, are intended to support growing energy needs, strengthen reliability, and allow for the connection of new resources.

Our advanced distribution management system allows operators to locate outages and control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid.

The system will also integrate a new meter data management system that will increase grid visibility and give customers access to more of their energy usage data.

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

We have 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.

We also increased spend on mitigating the risk associated with trees that could cause hazards, resulting in more of these trees being removed before they could cause outages or wildfires.

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

With recent wildfire events in Hawaii and across North America, we have been devoting and will continue to devote substantial efforts to analyzing and developing enhancements to our systems and processes to mitigate fire risk within our service territory and communities, including by hardening our infrastructure, deploying new technologies where appropriate, increasing our awareness, implementing operational

changes, and enhancing our wildfire response capabilities.

APS completed implementation of best-in-class fire modelling software that we are utilizing to more surgically identify and calculate risk and target future system improvement investments such as fire-resistant pole wrapping, wood to steel pole conversions, and additional remote-controllable field devices like reclosers and switches.

APS also currently intends to implement a public safety power shutoff (“PSPS”) program for this upcoming fire season, leveraging the additional real-time analysis provided by the new modelling software.

We continue to evaluate policy and regulatory options, as well as insurance programs, to mitigate the impact of wildfire events.

Maintaining reliability and affordability for our customers during the clean energy transition is fundamental to our strategy.

As a critical partner to the large quantity of renewables and energy storage we are adding to our system, natural gas generation will play an important role in maintaining reliability for our customers.

One example is the 2019 addition of new natural gas units at the modernized Ocotillo Power Plant to provide cleaner-running and more efficient units.

Additionally, efficiency improvements to gas units at the Redhawk and Sundance Power Plants are planned for completion prior to the summer of 2024.

As part of a balanced energy portfolio, these flexible resource additions 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.

Complementary to and in support of the transition to renewable resources, APS continues to evaluate options to meet growing energy demand and ensure grid reliability, including through upgrades to and/or modernization of additional existing natural gas facilities.

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

As a member 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 will go live with a new Energy Management System (“EMS”) in March of 2024.

The new EMS will better allow for integration of the renewable and energy storage assets into the APS’s generation resources.

This integration will allow APS to maximize the flexibility of our resources and fully engage in the Energy Imbalance Market.

It also better positions APS to participate in market opportunities that may develop through the next decade.

APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, customer partnerships to manage peak demand, fire mitigation, and operational preparedness.

Seasonal readiness procedures at APS also include inspections to ensure good material conditions and critical control system surveys.

APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.

APS continues to focus on mitigating the cost pressures related to the current inflationary environment.

Overall inflation grew by 2.7% in Phoenix and 3.4% nationally during 2023.

In 2022, overall inflation grew by 9.5% in Phoenix and 6.5% nationally.

The impacts from inflation have varied across separate categories of APS’s spending, including increases of up to 15% in 2023.

APS has seen inflationary impacts in supply constrained categories related to electrical equipment, such as transformers,

wire, and cable impacted by high utility demand outpacing manufacturing capacity.

Inflation continues to impact service rates and spend categories through pass-through costs such as supplier’s increased material costs, cost of insurance, and wage rates.

APS’s customer affordability initiative includes internal opportunities, such as training and mentoring employees on identifying efficiency opportunities;

maintaining an inventory to take advantage of lower pricing and avoid expediting fees;

entering into long-term contracts to hedge against price volatility, which has allowed APS to mitigate against procurement spend areas such as transformers;

and implementing automation technologies to enhance efficiencies and increase data-oriented decision making.

There are also external opportunities under APS’s customer affordability initiative, such as APS’s participation in the Western Energy Imbalance Market (“WEIM”).

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

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

APS is participating in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool.

APS also participated in the design and drafting of the tariff for the CAISO’s Extended Day-Ahead Market, which was approved by FERC in December 2023.

In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool.

These efforts are driven by three objectives of reducing customer cost, improving reliability, and incorporating more clean energy on APS’s system.

In terms of generation affordability, every three years, APS performs a comprehensive study, called an Integrated Resource Plan, to identify how much energy our customers will need over the next 15 years and what resources will be used to meet those needs.

In developing the IRP, APS considers factors that include how much economic growth is expected, what new technologies might be available and how weather can impact the demand for energy.

These inputs are then used to develop a plan that prioritizes reliability, affordability, and a clean, balanced energy mix.

In November 2023, APS released its latest IRP, which shows that energy demand is growing at an unprecedented rate.

This is due to continued residential and commercial customer growth throughout Arizona.

To keep pace with the fast-growing demand for electricity and maintain reliability, APS needs to add new electricity generating resources.

To ensure that the most affordable and reliable solutions are selected, APS issued All-Source Request for Proposals (“RFPs”) in 2022 and 2023.

These RFPs are open to all technologies, including customer-scale (behind the meter) and utility-scale (front of the meter) resources.

Through this process, APS has consistently found that clean resources like wind and solar, when coupled with energy storage technology, are among the most affordable options available today.

Over the long term, these resources are expected to provide the greatest value as part of a diverse energy mix.

In addition to managing the cost of electricity generation, APS has continued building upon existing cost management efforts, including a customer affordability initiative launched 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 achieving internal efficiencies.

APS continues to drive this initiative by identifying opportunities to streamline its business processes, mitigate cost increases, increase employee retention, and improve customer satisfaction.

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free.

We are committed to doing our part to build a clean and carbon-free future.

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

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

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

Our clean energy goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

APS’s clean energy goals consist of three parts:

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

We can accomplish our vision by collaborating with customers, communities, employees, policymakers, shareholders, and other stakeholders.

Our clean energy commitment is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

APS’s clean energy commitment consists of three parts:

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

• a 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy;

• a commitment to end APS’s use of coal-fired generation by 2031.

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

• A 2030 target to achieve a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy;

• A commitment to exit from coal-fired generation by 2031.

APS’s ability to successfully execute its clean energy commitment depends upon a number of important external factors, including a supportive regulatory environment, sales and customer growth, development of clean energy technologies, and continued access to capital markets among others.

100% Clean, Carbon-Free Electricity.

Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration.

The 2050 goal will involve new thinking and depends on improved and new technologies.

Achieving this 2050 goal will require, among other things, innovative thinking, emergent clean energy and storage technologies, upgrades and expansions to the grid, and supportive public policy.

65% Clean Energy.

APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025.

APS has an energy mix that is already 50% clean and plans to continue to add more renewables and energy storage.

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, 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.

End APS’s Use of Coal-Fired Generation.

The commitment to end APS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation at Four Corners.

“Renewable” energy includes generation resources 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 a 100% clean, carbon-free energy mix by 2050.

Exit Coal-Fired Generation.

The plan to exit coal-fired generation by 2031 will require APS to stop relying on coal-generation at Four Corners.

APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity.

These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of 33% since 2005.

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

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

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

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

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

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

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

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

All ordered payments and expenditures would be recoverable through rates.

See Note 3 for a discussion of the CCT plan.

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

(i) $3.33 million to the Navajo Nation;

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

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

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

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

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

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

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

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

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

APS and other interested parties filed comments on the report.

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

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

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

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

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.

These closures and other measures taken by APS have resulted in annual carbon emissions that were 24% lower in 2022 compared to 2005.

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

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 as early as 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.

The other unit would remain online year-round, subject to market

conditions as well as planned maintenance outages and unplanned outages.

As of the date of this report, APS has elected not to begin seasonal operation due to market conditions.

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

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

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

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

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

Its near-term actions are focused on clean, reliable energy and positive customer outcomes and include:

(a) competitive all source requests for proposal (“RFPs”) that provide an on-ramp to procure additional clean energy resources such as solar, wind, energy storage, and DSM resources, all of which lead to a cleaner grid and (b) strategic, short-term wholesale market purchases from a combination of existing merchant natural gas units, neighboring utility systems and wholesale market participants that ensure operational reliability.

APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas, that supports our commitment to clean energy.

This commitment is already strengthened by Palo Verde, one of the nation’s largest carbon-free, clean energy resource, which provides the foundation for reliable and affordable service for APS customers.

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

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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.

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

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

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

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

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

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

In December 2020, APS issued two additional RFPs:

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

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

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

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.

On June 30, 2023, APS issued an RFP (the “2023 RFP”) seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources with a focus on in-service dates between 2026 and 2028.

Bids from the 2023 RFP were received on September 6, 2023, and APS has started negotiations on multiple projects, including a 400 MW wind facility PPA that was signed in December 2023.

The following table summarizes the resources in APS’s renewable energy portfolio that are in operation or under development as of December 31, 2023.

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

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

Total APS Owned:

PPAs Renewables:

Solar 370 1,261

Geothermal 10 —

Total PPAs 1,034 1,877

Total Distributed Energy:

Solar (a) 1,623 61 (b)

Total Renewable Portfolio 3,072 1,938

(a) Includes rooftop solar facilities owned by third parties.

Distributed generation is produced in Direct Current and is converted to Alternating Current for reporting purposes.

(b) Applications received by APS that are not yet installed and online.

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 further our understanding of how storage works with other advanced technologies and the grid.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Service under this agreement is expected to begin in 2025.

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

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

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.

As noted above, on June 30, 2023, APS issued the 2023 RFP seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources, including energy storage, with a focus on in-service dates between 2026 and 2028.

APS currently plans to install more than 2,700 MW of utility scale energy storage by 2026, including through energy storage projects under PPAs and AZ Sun retrofits as well as through resources solicited through current and future RFPs.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2023.

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

Net Capacity in Operation

Net Capacity Planned / Under

Development (MW)

APS Owned Energy Storage

Net Capacity in Operation (MW) Net Capacity Planned / Under Development (MW)

APS Owned Energy Storage 182 (a) 19 (b)

PPAs Energy Storage 60 2,182

Residential Energy Storage 19(a) 7

Customer-Sited Energy Storage 30 20

Total Energy Storage Portfolio 272 2,221

(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 la rgest carbon-free, clean energy resource, will continue to be a foundational part of APS’s resource portfolio.

(a) Includes 0.3 MW of APS-owned customer-sited batteries.

(b) Includes 19 MW of capacity that entered commercial operation in January 2024.

Palo Verde, one of the nation’s largest carbon-free, clean energy resources, 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.

it also is a significant provider of clean energy to the southwestern United States.

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.

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.

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

APS continues to evaluate opportunities that benefit our customers and is exploring opportunities to move to a day-ahead market with the expectation of reliably achieving incrementally greater cost savings and using the region’s increasing renewable resources more efficiently.

As part of that effort, APS is exploring several options.

APS is in discussions with the current EIM operator, the CAISO, the Western Resource Adequacy Program, the Western Markets Exploratory Group, and the Southwest Power Pool.

Each of these explorations also involve other entities and are being undertaken to evaluate the feasibility and cost/benefit of creating a voluntary day-ahead market.

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

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.

Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid.

The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data.

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

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

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

The new units at our modernized Ocotillo Power Plant provide cleaner-running and more efficient units.

They support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening when solar production declines as the sun sets and customer demand peaks.

APS 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.

Seasonal readiness procedures at APS also include walkdowns to ensure good material conditions and critical control system surveys.

APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies.

Customer-Focused

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

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

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

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

APS made progress on that front in 2022.

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

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

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

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

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

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

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

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

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

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

an enhanced online power outage center;

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

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

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.

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.

Developing Clean Energy Technologies

Electric Vehicles

APS is making electric vehicle charging more accessible for its customers and helping Arizona businesses, schools and governments electrify their fleets.

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

As of 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 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.

As a part of the statewide transportation electrification plan (“TE Plan”) approved by the ACC in 2021, APS has a goal of supporting 450,000 light-duty electric vehicles (“EV”) in its service territory by 2030.

In furtherance of this goal, through its Take Charge AZ Pilot Program, and as of December 31, 2023, APS installed 758 Level 2 charging ports at 183 customer locations and DC fast charging stations that are owned and operated by APS at five locations in Arizona.

In December 2023, the ACC voted to discontinue the Take Charge AZ Pilot Program (“TCAZ”) while allowing APS to complete projects that were already underway.

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

The EV related programs in the DSM Plan also include the APS SmartCharge data gathering program, 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 2024 DSM Plan on November 30, 2023.

The 2024 DSM Plan includes APS’s 2024 TE Plan and, among other things, proposes two new programs:

an expanded residential EV Charging Demand Management Program, and a Commercial EV Make-Ready Program.

The ACC has yet to decide on the 2024 DSM Plan.

Hydrogen Production

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.

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.

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

AzCaNE’s first action was to pursue an Arizona-led approach to securing regional clean hydrogen hub

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 efforts.

AzCaNE submitted an initial hydrogen hub concept paper to the DOE, which in turn encouraged the submission of a full application for funding.

In response, AzCaNE formed the Southwest Clean Hydrogen Innovation Network (“SHINe”) and submitted an application for funding its behalf.

SHINe was not, however, selected as one of the seven regional hubs to be awarded funding by DOE.

APS is currently maintaining a participatory role in AzCaNE as the organization continues to explore ways to educate stakeholders and promote low-carbon technologies.

Carbon Capture

Carbon capture technologies can isolate CO 2 and either sequester it permanently in geologic formations or convert it for use in products.

Carbon Capture Utilization and Storage (“CCUS”) technologies can isolate CO 2 and either sequester it permanently in geologic formations or convert it for use in products.

Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen.

Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions.

CCUS technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions.

These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired.

APS will continue to monitor this emerging technology.

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

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

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

Our commitment extends beyond implementing sustainability practices;

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

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

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

identify and assess the sustainability issues that matter most.

APS will continue to monitor this emerging technology, particularly in regard to EPA’s proposed Greenhouse Gas (GHG) rule.

On May 23, 2023, the EPA proposed regulations for GHG emissions that would, among other things, require CCUS technologies for certain classifications of coal-, oil-, and natural gas-fired electricity generating units dependent upon a variety of factors including retirement date and operating capacity.

See Note 10 for more information.

Sustainability Practices

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

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

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

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

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

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

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

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

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

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

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

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

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

The framework is based upon three foundational pillars:

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

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

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

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

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

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

The Company also benchmarked best practices within the top four PSIs and has utilized this information to identify opportunities for improvement.

Finally, the Company maintains an annual Corporate Responsibility Report on the Pinnacle West website ( www.pinnaclewest.com/corporate-responsibility ).

The report provides information related to the Company’s sustainability practices and performance.

The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into or otherwise a part of this report.

Artificial Intelligence

To address the emergence of artificial intelligence technology risk and opportunities, APS has developed a cross functional governance structure with leadership and experts from our information technology, cybersecurity, human resources, ethics, supply chain, legal, and nuclear generation teams.

This cross functional structure will assess both the opportunities and risks during the technology intake process to ensure compliance with data security and reliability requirements, while observing market trends in this rapidly evolving area.

Regulatory Overview

3 unchanged sentences

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;

The principal provisions of APS’s application were:

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

• an original cost rate base of $ 10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

7 unchanged sentences

• 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,

▪ eliminate the Environmental Improvement Surcharge (“EIS”) and collect costs through base rates,

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

▪ maintain as inactive the Tax Expense Adjustor Mechanism (“TEAM”),

▪ maintain the Transmission Cost Adjustment (“TCA”) 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;

▪ modify the Renewable Energy Adjustment Charge (“REAC”) 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.

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

On June 5, 2023 and June 15, 2023, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC.

The ACC Staff recommends among other things, (i) a $251 million revenue increase or, as an alternative, a $312 million revenue increase, (ii) a 9.6% return on equity, (iii) a 0.0% fair value increment or, as an alternative, a 0.75% fair value increment, and (iv) a continuation of a 12-month post-test year plant.

RUCO recommends, among other things, (i) an $84.9 million revenue increase, (ii) an 8.2% return on equity or, as an alternative, an 8.7% return on equity if the ACC imputes a hypothetical capital structure with a 46% equity layer, (iii) a fair value increment of 0.0%, and (iv) a reduction of post-test year plant to six months.

On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies.

The principal provisions of APS’s rebuttal testimony were:

• reducing the revenue requirement increase to $383.1 million, which reduced the average annual customer bill impact to an increase of 11.3%;

• maintaining a return on equity request of 10.25%;

• reducing the increment of fair value rate base return to 0.5% from 1.0%;

• maintaining a post-test year plant request of 12 months, plus the Four Corners Effluent Limitation Guidelines (“ELG”) project;

• withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application;

• maintaining the LFCR and DSMAC as separate adjustors;

• increasing the PSA annual rate change limit from $0.004/kWh to $0.006/kWh;

• proposing a new System Reliability Benefit (“SRB”) recovery mechanism;

• maintaining the REAC in its current state;

• maintaining adjustor base transfers and elimination of EIS;

• maintaining the request to recover CCT funding.

On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC.

The ACC Staff adjusted their initial recommendations to, among other things, (i) a $281.9 million revenue increase, (ii) a 9.68% return on equity, (iii) a 0.5% fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $0.006/kWh.

RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 Rate Case.

On August 4, 2023, APS filed rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies.

APS’s rejoinder testimony included final post-Test Year Plant values, reducing the revenue requirement increase to $377.7 million from $383.1 million, which reduced the average annual customer bill impact to an increase of 11.2%.

All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony.

On November 6, 2023, and November 21, 2023, APS and stakeholders filed briefs in the 2022 Rate Case.

APS’s briefs included the reduction of the total revenue requirement increase to $376.2 million and a resulting average annual customer bill impact increase of 11.1%.

All other major provisions from APS’s rejoinder testimony were maintained in its briefs.

ACC Staff’s briefs included a proposed total revenue

requirement increase from $281.9 million to $282.7 million and also included their support of APS’s SRB mechanism, contingent on increased stakeholder outreach.

On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”).

The 2022 Rate Case ROO recommended, among other things, (i) a $523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36%, (v) 12 months of post-test year plant and the inclusion of the Four Corners ELG project, (vi) the approval of APS’s SRB proposal with certain procedural and other modifications, (vii) no additional CCT funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the OPEB liability, and (ix) no disallowances on APS’s coal contracts.

The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $1.9 million of REAC in the adjustor rather than base rates, (iii) a partial transfer of $27.1 million of LFCR funds to base rates, and (iv) the adoption of an increase in the annual PSA cap to $0.006/kWh.

On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source RFP, and (viii) recovery of all DSM costs through the DSMAC rather than through base rates.

The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill.

The ACC is expected to issue the final order for the 2022 Rate Case in March 2024 with the new rates to become effective for all service rendered on and after March 8, 2024.

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.

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

On August 2, 2021, an 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.

Subsequently, the ACC approved an amended 2019 Rate Case ROO on November 2, 2021 (the “2019 Rate Case Decision”).

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 $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.

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

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

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

On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215.5 million of Four

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.

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

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

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

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

(i) $3.33 million to the Navajo Nation;

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

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

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

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

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

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

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

After the 2019 Rate Case Decision, APS filed an application for rehearing of the 2019 Rate Case and later filed a Notice of Direct Appeal by APS at the Arizona Court of Appeals, requesting review of certain matters from the 2019 Rate Case Decision.

The Arizona Court of Appeals affirmed in part and reversed in part the ACC’s decision in the 2019 Rate Case, remanding the issue to the ACC for further proceedings.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to

allow recovery of $215.5 million in costs related to the installation of the Four Corners SCR project, a reversal of the 20-basis point reduction to APS’s return on equity from 8.9% to 8.7% as a result of the 2019 Rate Case Decision, and recovery of $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023.

The joint resolution provides for a new Court Resolution Surcharge (“CRS”) mechanism, which is designed to recover the $59.6 million in revenue lost by APS between December 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates.

On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the CRS mechanism, which became effective on July 1, 2023.

The current CRS will be recalculated at the end of the 2022 Rate Case to remove the effects of the prospective recovery related to the allowable return on equity difference.

On February 22, 2024, the ACC approved the 2022 Rate Case.

The CRS tariff is currently being recalculated to reflect the final decision in that case.

See Note 3 for more information regarding the 2019 Rate Case and Four Corners SCR cost recovery.

The portion of the CRS representing the recovery of the $59.6 million of lost revenue between December of 2021 and June 20, 2023, $9.4 million of which has been collected as of December 31, 2023, will cease upon full collection of the lost revenue.

Finally, recovery of ongoing costs related to the SCR investments will continue until the Company’s next rate case in which they can be incorporated therein.

Regulatory Lag Docket

On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules.

The ACC requested comments from utilities and interested parties on ways to reduce regulatory lag, including alternative ratemaking structures such as future test years and hybrid test years.

APS filed comments on June 1, 2023.

APS cannot predict the outcome of this matter.

See Note 3 for information regarding additional regulatory matters.

Four Corners SCR Cost Recovery

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

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

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

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

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

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

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

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

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

See Note 3 for additional information regarding the Four Corners SCR cost recovery.

Financial Strength and Flexibility

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Other Subsidiaries

Bright Canyon Energy .

On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE.

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

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.

PNW Power and BCE .

On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary BCE to Ameresco (the “BCE Sale”).

The transaction was accounted for as the sale of a business and closed in multiple stages.

Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to Pinnacle West Power, LLC (“PNW Power”), a newly-formed, wholly-owned subsidiary of Pinnacle West.

The BCE Sale transaction was accounted for as the sale of a business and closed in multiple stages.

As of December 31, 2023, all of BCE assets were classified as held for sale.

The final closing of the BCE Sale was on January 12, 2024.

See Note 20 for additional details.

PNW Power’s investments include TransCanyon, a 50/50 joint venture that was formed in 2014 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 U.S.

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.

PNW Power’s investments also include minority ownership positions in two wind farms operated by Tenaska Energy, Inc.

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

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

Clear Creek achieved commercial operation in May 2020;

however, in the fourth quarter of 2022, PNW Power’s equity method investment was fully impaired.

Nobles 2 achieved commercial operation in December 2020.

Both wind farms deliver power under long-term PPAs.

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

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

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

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

FERC has not ruled on the motion for stay.

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

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

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

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

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

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

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

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

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

BCE has started construction on a microgrid facility in Los Alamitos, California 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.

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

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

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

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

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

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

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

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

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

In particular, El Dorado has committed to the following:

• $25 million investment in the Energy Impact Partners fund, of which $16.7 million has been funded as of December 31, 2023.

Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry.

• $25 million investment in AZ-VC (formerly invisionAZ Fund), of which $6.3 million has been funded as of December 31, 2023.

AZ-VC 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 Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona.

The remainder of these investment commitments will be contributed by El Dorado as each investment fund selects and makes investments.

Key Financial Drivers

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Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.5% for the year ended December 31, 2023, 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.

While steady customer growth was somewhat offset by weaker usage among residential customers, energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong sales to commercial and industrial customers and the ramp-up of new data center customers.

For the three years through 2023, annual retail electricity sales growth averaged 2.7%, adjusted to exclude the effects of weather variations.

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.

Due to the expected 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 2.0% to 4.0% for 2024 and that average annual growth will be in the range of 4.0% to 6.0% through 2026, including the effects of customer conservation, energy efficiency, and distributed renewable generation initiatives, but excluding the effects of weather variations.

These projected sales growth ranges include the impacts of several large data centers and new large manufacturing facilities, which are expected to contribute to 2024 growth in the range of 2.5% to 3.5% and to average annual growth in the range of 3.0% to 5.0% through 2026.

Longer term, APS has been preparing for and can serve significant load growth from residential and business customers.

On top of these existing growth trends, APS is also now receiving unprecedented incremental requests for service from extra-large commercial energy users (over 25 MW) with very high energy demands that persist virtually around-the-clock.

These incremental requests for service by extra-large energy users far exceed available generation and transmission resource capacity in the Southwest region for the foreseeable future.

In April 2023, APS notified prospective extra-large customers without existing commitments from APS that it is not able to commit at this time to future extra-large projects of over 25 MW.

Because of the high growth in demand for such projects, APS has developed a prioritization queue that identifies and prioritizes projects while maintaining system reliability and affordability for existing APS customers.

APS is exploring available options for securing sufficient electric generation and transmission to meet these projections of future customer needs.

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, responses to retail price changes, changes in regulatory standards, and impacts of new and existing laws and regulations, including environmental laws and regulations.

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

Our experience indicates that typical variations from normal weather can result in increases and 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.

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The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.0% of the assessed value for 2023, 10.2% for 2022, and 10.7% for 2021.

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.

Property taxes increased in 2023 due to higher plant balances related to expansion and improvements on our existing generation, transmission, and distribution facilities, partially offset by legislative changes reducing both property tax assessment ratios and rates in Arizona.

Income Taxes .

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In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted and was generally effective on January 1, 2018.

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

See Note 4 for details of the impacts on the Company as of December 31, 2022.

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

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

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

See Note 3 for details of the TEAM.

Interest Expense.

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An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction.

We stop accruing AFUDC on a project when it is placed in commercial operation.

We stop accruing AFUDC on a project when it is placed into service.

RESULTS OF OPERATIONS

Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost-based rate regulation) and related activities and includes electricity generation, transmission, and distribution.

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost-based rate regulation) and related activities and includes electricity generation, transmission, and distribution.

All other segment activities are insignificant.

Our regulated electricity segment activities are conducted primarily through our wholly-owned subsidiary, APS.

Operating Results – 2023 compared with 2022

Our consolidated net income attributable to common shareholders for the year ended December 31, 2023, was $502 million, compared with $484 million for the prior year.

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:

2022 2021 Net change

The results reflect an increase of approximately $18 million, primarily as a result of the effects of weather, higher CRS and LFCR revenue, higher transmission revenue, increased sales and usage, and higher other income.

These positive factors were partially offset by higher interest charges, net of AFUDC, higher operations and maintenance expense, lower pension and other postretirement non-service credits, and higher depreciation and amortization expense mostly due to increased plant assets.

The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated:

APS Consolidated Pinnacle West Consolidated

Year Ended December 31,

2023 2022 Net

Change 2023 2022 Net

(dollars in millions)

Regulated Electricity Segment:

Operating revenues $ 4,696 $ 4,324 $ 372 $ 4,696 $ 4,324 $ 372

Fuel and purchased power expense (1,793) (1,629) (164) (1,793) (1,629) (164)

Operating revenues less fuel and purchased power expenses 2,903 2,695 208 2,903 2,695 208

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Pension and other postretirement non-service credits, net 42 99 (57) 41 98 (57)

All other income and expenses, net 23 61 (38)

Other income and expenses, net 60 22 38 60 (1) 61

Interest charges, net of allowance for borrowed funds used during construction (285) (236) (49) (331) (256) (75)

Income taxes (Note 4)

(75) (110) 35

Less income related to noncontrolling interests (Note 17)

Regulated electricity segment income 508 622 (114)

All other (24) (3) (21)

Income taxes (94) (91) (3) (77) (75) (2)

Less income related to noncontrolling interests (17) (17) — (17) (17) —

Net Income Attributable to Common Shareholders $ 547 $ 525 $ 22 $ 502 $ 484 $ 18

Operating revenues less fuel and purchased power expenses .

Regulated electricity segment operating revenues less fuel and purchased power expenses were $45 million higher for the year ended December 31, 2022, compared with the prior year.

Operating revenues less fuel and purchased power expenses were $208 million higher for the year ended December 31, 2023, compared with the prior year.

The following table summarizes the major components of this change:

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(dollars in millions)

Lower refunds in the current year related to the Tax Act (Note 3)

LFCR revenue (Note 3)

$ 55 $ — $ 55

Effects of weather 46 12 34

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

CRS revenue (Note 3)

Higher transmission revenues (Note 3)

Higher retail revenue due to customer growth and changes in customer usage patterns and related pricing, partially offset by the impacts of energy efficiency and distributed generation 39 14 25

Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs 15 (8) 23

Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals 158 145 13

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 (1) 1 (2)

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Operations and maintenance .

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;

Operations and maintenance expenses increased $72 million for the year ended December 31, 2023, compared with the prior-year period primarily due to:

• An increase of $31 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

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

• An increase of $22 million related to non-nuclear generation costs primarily due to higher operating costs and higher planned outages;

• An increase of $14 million related to transmission, distribution, and customer service;

• An increase of $13 million related to nuclear generation costs;

• An increase of $10 million related to information technology costs;

• A decrease of $26 million related to employee benefits, largely due to decreased pension and other post-retirement service costs of $12 million and other miscellaneous factors.

See “pension and other postretirement non-service credits, net” below for additional discussion;

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

Depreciation and amortization.

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 $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.

Depreciation and amortization expenses were $41 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to increased plant in service.

Pension and other postretirement non-service credits, net.

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 $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.

Pension and other postretirement non-service credits, net were $57 million lower for the year ended December 31, 2023, compared to the prior-year period primarily due to the effect of higher discount rates and actual market returns being lower than estimated returns in 2022.

Other income and expenses, net.

All other income and expenses, net were $61 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to higher interest income, higher allowance for equity funds used during construction due to increased capital expenditures, Clear Creak wind farm impairment (see Note 10) recorded in the prior year period, and the gain on the BCE Sale.

The difference between APS’s and Pinnacle West’s other income and expenses, net primarily relates to BCE matters.

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

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

Interest charges, net of allowance for borrowed funds used during construction were $75 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to higher debt balances, higher commercial paper balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.

The difference between APS’s and Pinnacle West’s interest charges, net of allowance for borrowed funds used during construction is primarily relates to Pinnacle West’s higher term loan interest and BCE debt activity.

Income taxes.

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.

Income taxes were $2 million higher for the year ended December 31, 2023, compared with the prior-year period primarily due to higher pre-tax income, partially offset by Investment Tax Credit amortization from our Arizona Sun battery facilities, and Production Tax Credits from our Agave Solar facility, both of which went into service in 2023.

LIQUIDITY AND CAPITAL RESOURCES

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This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

Dividends to Pinnacle West from APS are also dependent on a number of factors including, among others, APS’s financial condition and free cash flow, the sources of which vary from quarter-to-quarter due in part to the seasonal nature of electricity demand.

APS’s sources of cash include cash from operations and external sources of liquidity, including long- and short-term external debt financing such as

commercial paper and its revolving credit facility.

APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt.

APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West.

APS is currently authorized to receive up to $150 million annually in equity infusions from Pinnacle West without seeking ACC approval.

On October 27, 2023, APS sought approval from the ACC to receive from Pinnacle West in 2024 up to an additional $500 million in equity infusions above the authorized limit of $150 million, and on January 9, 2024, the ACC approved the increased equity infusion limit for 2024.

Pinnacle West and APS maintain committed revolving credit facilities that enhance liquidity and provide credit support for accessing commercial paper markets.

These credit facilities mature in 2028.

Summary of Cash Flows

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2023 Compared with 2022.

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.

Pinnacle West’s consolidated net cash provided by operating activities was $1,207 million in 2023 compared to $1,242 million in 2022, a decrease of $35 million in net cash provided primarily due to $204 million higher fuel and purchased power costs, $82 million higher payments for operations and maintenance costs, $66 million higher interest payments, $57 million lower customer advances for construction and $13 million change in net collateral, partially offset by $349 million higher cash receipts from electric revenues and $37 million lower income taxes.

The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s lower income tax cash payments to Pinnacle West and other changes in working capital.

Retirement plans and other postretirement benefits.

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

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

The requirements of the Employee Retirement Income

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

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

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

We made contributions to our pension plan totaling $0 million in 2022, $100 million in 2021, and $100 million in 2020.

In 2022 and 2023, we did not make any contributions to our pension plan.

In 2021, we made contributions to our pension plan totaling $100 million.

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 2024, 2025 or 2026.

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.

Regarding contributions to our other postretirement benefit plan, we did not make any contributions in 2023 or 2022 and do not expect to make any contributions in 2024, 2025 or 2026.

The Company was reimbursed $23 million in 2023, $26 million in 2022, and $24 million in 2021 for prior years retiree medical claims from the other postretirement benefit plan trust assets.

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2023 Compared with 2022.

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.

Pinnacle West’s consolidated net cash used for investing activities was $1,694 million in 2023 compared to $1,618 million in 2022, an increase of $76 million primarily related to increased capital expenditures and higher allowance for borrowed funds, partially offset by proceeds from the BCE Sale.

The difference between APS’s and Pinnacle West’s net cash used for investing activities primarily relates to the BCE Sale.

Capital Expenditures.

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

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

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

Generation capital expenditures also include improvements to existing fossil plants.

Generation capital expenditures also include additions and improvements to existing fossil plants, such as our current modernization project at our Sundance gas plant.

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

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2023 Compared with 2022.

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.

Pinnacle West’s consolidated net cash provided by financing activities was $487 million in 2023 compared to $371 million in 2022, an increase of $116 million in net cash provided primarily due to a net increase in short-term borrowings of $193 million and $117 million lower long-term debt repayments, partially offset by $186 million in lower issuances of long-term debt and higher dividend payments of $8 million.

APS’s consolidated net cash provided by financing activities was $412 million in 2023 compared to $314 million in 2022, an increase of $98 million in net cash provided primarily due to a net increase in short-term borrowings of $135 million, partially offset by $29 million in lower issuances of long-term debt and higher dividend payments of $8 million.

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.

On December 15, 2022, the ACC issued a financing order reaffirming the previous 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) and 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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• APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033.

CRITICAL ACCOUNTING POLICIES

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period.

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

Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities.

Management judgments also include assessing the impact of potential ACC- or FERC-ordered refunds to customers on regulatory liabilities.

We had $2,016 million of regulatory assets and $2,176 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2023.

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

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

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.

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AROs as of December 31, 2023 are described further in Note 11.

OTHER ACCOUNTING MATTERS

See Note 21 for two new accounting standards that were issued in November and December 2023, respectively, that are pending adoption:

ASU 2023-07, Improvements to Reportable Segment Disclosures, effective for us for annual periods on December 31, 2024, and interim periods thereafter, and ASU 2023-09, Improvements to Income Tax Disclosures, effective for us for annual periods on December 31, 2025.

MARKET AND CREDIT RISKS

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

Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Nuclear decommissioning, coal reclamation, and benefit plan costs are recovered in regulated electricity prices.

The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2023, and 2022.

If variable interest rates were to increase by 10% from the December 31, 2023, levels, it would not have a material effect on Pinnacle West Consolidated or APS Consolidated annual interest expense.

The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2023, and 2022 (dollars in millions):

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

Increase (decrease) in regulatory liability (11) 120

Decrease (increase) in regulatory asset (216) (11)

Mark-to-market of net positions at end of year $ (120) $ 96

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December 31, 2023

Gain (Loss) December 31, 2021

December 31, 2022

Price Up 10% Price Down 10% Price Up 10% Price Down 10%

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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