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

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and APS’s Condensed Consolidated Financial Statements and the related Combined Notes that appear in Item 1 of this report. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Part 1, Item 1A of the 2023 Form 10-K and Part II, Item 1A of this report.

OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $26 billion. Since 1886, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS. APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.4 million retail customers in 11 of Arizona’s 15 counties. APS is also the operator and co-owner of Palo Verde Generating Station (“Palo Verde”) — a primary source of electricity for the southwestern United States.

Inflation Reduction Act of 2022

The Inflation Reduction Act of 2022 (“IRA”) significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage. 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; (iii) introduction of technology neutral clean energy ITCs and PTCs beginning in 2025; and (iv) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032. The Internal Revenue Service and U.S. Treasury Department 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. See Note 17 for more information.

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.

Strategic Overview

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. 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’s progress on this front has continued in 2024.

In furtherance of a customer-centric culture, APS employees have delivered an enhanced customer experience in recent years through a number of past and ongoing initiatives, including improving the ease-of-use of APS’s automated phone system and advancing phone advisor soft skill development through updated training curriculum, and adding 1,100-plus in-person payment locations, as well as introducing new customer payment channels. APS also implemented numerous enhancements to its website, including improving page-loading speeds, adding user-friendly dashboards, and making content more simple, relevant, and useful. APS enhanced other customer touchpoints, such as communications throughout outages and the online outage center in addition to continuing to communicate with customers in their preferred channels about topics that matter most to them, such as reliability, energy-efficiency, financial assistance, the environment, and programs that enable them to design their own personalized energy experience. To further improve customer communications, APS expanded the use of email and text alerts, notifications, and communications to customers related to outages and their account and service status. Finally, APS continues to focus on employee learning, training, tools, and resources to ensure all employees understand their role in APS customers’ experiences.

Additionally, APS has implemented a variety of financial assistance programs to assist customers struggling to pay their energy bills. Among these assistance programs are discounts for qualified limited-income customers, including a new tier with larger discounts added for APS’s lowest income customers added in the second quarter of 2024, and other non-income-based assistance programs, such as flexible payment arrangements and emergency utility bill assistance. To ensure our most vulnerable customers are connected to these programs, we train and partner with more than one hundred community action agencies across our service territory.

Reliable

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 those experienced in 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 customer energy needs, APS has developed a future-focused, strategic transmission plan (the “Ten-Year Transmission Plan”). This Ten-Year Transmission 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 Transmission 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 has implemented a public safety power shutoff (“PSPS”) program for this upcoming fire season, leveraging the additional real-time analysis provided by the new modelling software, and is continuing education outreach to customers and communities that may potentially be impacted by the PSPS program. 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. A balanced energy portfolio is vital to maintaining reliability, and natural gas resources play a backup role to intermittent energy resources by providing energy when solar and wind resources are less effective and/or customer demand peaks. In addition to new natural gas units at the modernized Ocotillo Power Plant in 2019 and efficiency improvements at gas units at the Redhawk, Sundance, and West Phoenix Power Plants in 2024, APS continues to evaluate and pursue options to reliably serve growing energy demand, including the potential addition of more natural gas generating units. For example, APS has contracted for two simple cycle combustion turbines (approximately 90 MW in total) at the Sundance Power Plant, which are expected to be in service in 2026.

In October 2021, APS announced plans to evaluate regional market solutions as part of the Western Markets Exploratory Group (“WMEG”). As a member of WMEG, APS explored 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 regulations and known and expected market design. APS utilizes the work done by WMEG to help identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers.

APS went live with a new Energy Management System (“EMS”) in April 2024. APS expects the new EMS to provide a better foundation which will improve future integration of the renewable and energy storage assets into APS’s generation resource portfolio, allowing APS to maximize the flexibility of its resources and fully engage in the Energy Imbalance Market. APS also believes it will better position APS to participate in market opportunities that develop over the next decade.

APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, partnering with customers to manage peak demand, fire mitigation, and operational preparedness, among others. 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.

Affordable

APS continues to focus on mitigating the cost pressures related to the current inflationary environment. Overall inflation grew by 2.7% in Phoenix and 3.0% nationally over the twelve months ended June 2024. While inflationary impacts to APS have begun to slow in 2024, select categories have seen increases up to 24% in the quarter ended June 30, 2024, due to increased labor costs and costs of certain materials. Additionally, APS has seen inflationary impacts in select equipment, particularly those that contain semiconductor components or that are labor intensive. Inflation continues to impact service rates and spend categories through pass-through costs, such as suppliers’ 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 participated in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool that was filed with the U.S. Federal Energy Regulatory Commission (“FERC”) on March 29, 2024. 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 regional 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 (“IRP”), to identify what resources will be necessary to safely and reliably meet the demand and energy needs of its customers over the next 15 years. In November 2023, APS released its latest IRP, which identified forecasted customer demand and energy needs growing at an unprecedented rate. In developing the IRP, APS considered how factors such as forecasted economic growth, new resource technology availability, and weather impact the amount and type of resources required to reliably meet customer needs. These inputs are then used to develop a plan that identifies a balanced mix of energy generating resources that reliably serves customers’ future energy needs in the most affordable and sustainable manner possible. Ensuring that the most affordable and reliable resources are selected to meet future customer needs, APS issued competitive solicitations through all-source request for proposals (“RFPs”) in 2022 and 2023. These RFPs were open to all resource types, 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, solar, and energy storage technology, are important elements of a least cost portfolio. Over the long term, these resources are expected to provide 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 areas ranging from 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 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 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 to achieve a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and

• 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.

2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. 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.

2030 Goal: 65% Clean Energy. APS has an energy mix that is already more than 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 resources such as solar, wind, and biomass, and is measured in accordance with the Arizona Corporation Commission’s (the “ACC”) 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.

2031 Goal: Exit Coal-Fired Generation. The plan to exit coal-fired generation by 2031 will require APS to stop relying on coal-generation at the Four Corners Power Plant (“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 annual carbon emissions that were 36% lower in 2023 compared to 2005. In addition, APS has committed to end the use of coal at its remaining Cholla Power Plant 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. As of the date of this report, APS has elected not to begin seasonal operation due to market conditions.

Renewables. APS’s IRP identifies a diverse mix of resources adequate to maintain grid reliability while serving increasing future customer energy needs. Our IRP shows that renewable and clean resources are an important part of a reliable, cost effective portfolio. APS seeks market-based pricing of procured resources through regular solicitation of project bids using its competitive RFP process.

APS has a diverse portfolio of existing and planned resources, including solar, wind, energy storage, nuclear, 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 resources, procurement of new resources to be owned by APS, and the ongoing development of distributed energy resources. Maintaining a balanced and diverse portfolio of resources will ensure continued reliable service to our customers in the most affordable manner possible.

APS uses competitive RFPs to pursue market-priced resources that meet its system needs and offer the best value for customers. 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. Guided by IRP-established timelines and quantities, APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the RFP process. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection to the electric grid.

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 is negotiating on multiple projects and executed agreements on multiple others, including a 500 MW wind facility power purchase agreement (“PPA”) and a 168 MW solar facility that APS will own and operate.

The following table summarizes the resources in APS’s renewable energy portfolio that are in operation or under development as of June 30, 2024. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting, and interconnection of the projects to the electric grid.

			Net Capacity in Operation (MW)						Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar			416						168
Purchased Power Agreements Renewables:
Solar			585						1,046
Wind			853						500
Geothermal			10						—
Biomass			14						—
Biogas			3						—
Total Purchased Power Agreements			1,465						1,546
Total Distributed Energy: Solar (a)			1,681						54			(b)
Total Renewable Portfolio			3,562						1,768

(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. APS deploys a number of advanced technologies on its system, including energy storage. Energy storage provides capacity, improves power quality, can be utilized for system regulation and, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage also aids in integrating renewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to meet customer reliability requirements, increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid.

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. From those bids, APS has since executed agreements for a 150 MW energy storage facility that APS will own and operate and a 150 MW energy storage PPA.

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 Program 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 or under development as of June 30, 2024. Agreements for the development and completion of future resources are subject to various conditions.

			Net Capacity in Operation (MW)						Net Capacity Planned / Under Development (MW)
APS Owned: Energy Storage			201			(a)			150
Purchase Power Agreements - Energy Storage			355						2,037
Customer-Sited Energy Storage			35						23
Total Energy Storage Portfolio			591						2,210

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

Palo Verde. 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 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.

Developing Clean Energy Technologies

Electric Vehicles

As a part of the statewide transportation electrification plan (“TE Plan”) adopted in 2021, the ACC approved a target of 450,000 light-duty electric vehicles (“EVs”) in its service territory by 2030. APS’s Take Charge AZ (“TCAZ”) program has helped to deploy Level 2 EV charging stations on customer properties for fleet, public, and workplace EV charging. As of June 30, 2024, APS energized 809 Level 2 charging ports at 193 customer locations. Additionally, APS has energized direct current fast charging (“DCFC”) stations that are owned and operated by APS at five locations in Arizona: Sedona, Prescott, Globe, Show Low, and Payson. Effective December 12, 2023, the TCAZ program was discontinued by the ACC. As part of that decision, APS was permitted to complete certain projects that were in process as of December 12, 2023.

Additionally, as part of APS’s DSM Implementation Plan, APS launched the EV Charging Demand Management Pilot to proactively address the growing electric demand from charging as EVs become more widely adopted. The EV programs in the DSM Implementation Plan include APS SmartCharge (an EV data gathering program), Fleet Advisory Services, and a $100 rebate to home builders for new homes to be built EV-ready with 240V receptacle. APS previously offered a $250 residential rebate to customers that purchased a qualifying home Level 2 charger. Effective December 12, 2023, APS discontinued this rebate per the ACC decision. See the discussion above.

APS filed its 2024 DSM Implementation Plan on November 30, 2023. The 2024 DSM Implementation Plan includes APS’s 2024 TE Plan and, among other things, proposes two new programs: an expanded residential EV Managed Charging program and a Commercial EV Make-Ready Program. On April 26, 2024, APS filed an amended 2024 DSM Implementation Plan. The amended 2024 DSM Implementation Plan includes an updated budget to reflect removal of incentive funds for the Level 2 Smart Charger rebate within the EV Charging Demand Management Pilot, an update on the performance incentive calculation, and the withdrawal of tranches two and three of the residential battery pilot. The amended 2024 DSM Plan is still pending ACC review and approval. APS cannot predict the outcome of this proceeding. See Note 4.

Carbon Capture

Carbon Capture Utilization and Storage (“CCUS”) technologies can isolate CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. 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, particularly in regard to the U.S. Environmental Protection Agency’s (“EPA”) proposed Greenhouse Gas (“GHG”) rule. On April 25, 2024, the EPA issued a final rule that, among other things, requires the installation of carbon capture technology for certain classifications of coal, oil, and natural gas fired electricity generating units dependent upon certain factors, including retirement date and operating capacity. See Note 8 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 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 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 rapid advancement 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 assesses 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

2022 Retail Rate Case

APS filed an application with the ACC on October 28, 2022 (the “2022 Rate Case”) seeking an increase in annual retail base rates on the date rates become effective (“Day 1”) of a net $460 million. This Day 1 net impact would have represented a total base revenue deficiency of $772 million, offset by proposed adjustor transfers of cost recovery to annual retail rates and adjustor mechanism modifications. The average annual customer bill impact of APS’s request on Day 1 would have been an increase of 13.6%.

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;

• the following proposed capital structure and costs of capital:

									Capital Structure						Cost of Capital
Long-term debt									48.07		%				3.85		%
Common stock equity									51.93		%				10.25		%
Weighted-average cost of capital															7.17		%

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

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

• modification of its adjustment mechanisms including:

▪eliminate the Environmental Improvement Surcharge (“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 (“DSM”) 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 (“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; and

• 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 recommended, 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 recommended, 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 mechanism 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; and

• 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 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 issued the final order for the 2022 Rate Case on March 5, 2024, with the new rates becoming effective for all service rendered on or after March 8, 2024.

Six intervenors and the Attorney General of Arizona requested rehearing on various issues included in the ACC’s decision, such as the grid access charge (“GAC”) for solar customers, the SRB, and CCT funding. On April 15, 2024, the ACC granted, in part, the rehearing applications of the Attorney General, Arizona Solar Energy Industries Association, Solar Energy Industries Association, and Vote Solar for the limited purpose of reviewing arguments concerning the GAC. Specifically, rehearing was ordered as to whether the GAC rate is just and reasonable, including whether it should be higher or lower, whether the GAC rate constitutes a discriminatory fee to solar customers, and whether omission of a GAC charge is discriminatory to non-solar customers. All other applications for rehearing were denied. The parties seeking rehearing had 30 days after the denial or granting of a request for rehearing to file a notice of appeal to the Arizona Court of Appeals. No party filed a notice of appeal within the 30-day period. A limited rehearing is scheduled to begin on November 5, 2024 for the purpose of reviewing the GAC. APS cannot predict the outcome of these proceedings.

2019 Retail Rate Case

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. See Note 4 for information regarding the 2019 Rate Case ROO.

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 selective catalytic reduction (“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 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. As of June 30, 2024, $16.8 million of the $59.6 million of lost revenue has been recovered. Finally, the CRS tariff has been updated to account for changes to return on equity and depreciation and deferral adjustments approved in Decision No. 79293 in the 2022 Rate Case. See Note 4 for more information regarding the 2019 Rate Case and Four Corners SCR cost recovery.

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. On March 19, 2024, the ACC held a workshop to discuss modifying the state’s rate case test year rules. Utilities, including APS, spoke about alternatives to the current rules that could reduce regulatory lag. The ACC plans to hold another workshop on this topic and has invited further comments from stakeholders. On April 19, 2024, a letter was filed to the docket by an ACC commissioner discussing the potential benefits of modifying test year rules, including the potentiality of offering utilities to choose the type of test year that best suits them. The letter also recommended that this issue be discussed at the next possible open meeting. On July 9, 2024, at an open meeting, ACC Commissioners discussed objectives of future regulatory lag workshops and voted to schedule at least one more workshop on this topic later this year. The ACC scheduled a workshop for October 3, 2024. APS cannot predict the outcome of this matter.

See Note 4 for information regarding additional regulatory matters.

Financial Strength and Flexibility

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

Other Subsidiaries

Pinnacle West Power, LLC (“PNW Power”). 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. The final closing of the BCE Sale was completed on January 12, 2024. See Note 16 for additional details. 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 PNW Power, a wholly-owned subsidiary of Pinnacle West.

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. 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. The U.S. Department of Energy’s Grid Deployment Office selected TransCanyon to enter into capacity contract negotiations for up

to 25% of the Cross-Tie 500-kilovolt transmission line (“Cross-Tie”) as part of the Transmission Facilitation Program. The agreement was executed on June 12, 2024. The proposed Cross-Tie project includes a 214-mile transmission line connecting Utah and Nevada that is intended to help improve grid reliability and relieve congestion on other transmission lines.

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

El Dorado Investment Company (“El Dorado”). El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. In particular, El Dorado has committed to the following:

• $25 million investment in the Energy Impact Partners fund, of which $18.1 million has been funded as of June 30, 2024. 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 $10.5 million has been funded as of June 30, 2024. 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.

• $7.5 million investment in Westly Seed Fund, of which $0.8 million has been funded as of June 30, 2024. Westly Seed Fund is focused on supporting entrepreneurs who are revolutionizing the energy, mobility, building, and industrial sectors.

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

Key Financial Drivers

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

Electric Operating Revenues. For the years 2021 through 2023, retail electric revenues comprised approximately 91% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand, and prices.

Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.0% for the six-month period ended June 30, 2024, compared with the prior-year period. For the three-year period ended 2023, APS’s customer growth averaged 2.1% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2024 and the average annual growth to be in the range of 1.5% to 2.5% through 2026 based on anticipated steady population growth in Arizona during that period.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 5.6% for the six-month period ended June 30, 2024, compared with the prior-year period. 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-year period ended 2023, annual retail electricity sales growth averaged 2.6%, adjusted to exclude the effects of weather variations. 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. 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.

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

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

Operations and Maintenance Expenses**.** Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and DSM related expenses (which are mostly offset by the same amount of operating revenues) and other factors.

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

Pension and Other Postretirement Non-Service Credits, Net*.* Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary. See Note 5.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by changes in plant balances related to new investments and improvements to existing facilities, the value of property in service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.0% of the assessed value for 2023, 10.2% for 2022, and 10.7% for 2021.

Income Taxes**.** Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions, and non-taxable items, such as allowance for funds used during construction (“AFUDC”). In addition, income taxes may also be affected by the settlement of issues with taxing authorities. See Note 17.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. See Note 3 for further details. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed into service.

RESULTS OF OPERATIONS

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 — Three-month period ended June 30, 2024, compared with three-month period ended June 30, 2023.

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2024, was $204 million, compared with consolidated net income attributable to common shareholders of $107 million for the prior-year period. The results reflect an increase of approximately $97 million, primarily as a result of the impacts of new customer rates, the effects of weather, increased customer usage and growth, and higher CRS revenue. These positive factors were partially offset by higher depreciation and amortization expense mostly due to increased plant and intangible assets, higher interest charges, net of AFUDC, and higher income taxes, partially offset by the favorable timing of recognition for permanent items and credits.

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

			Pinnacle West Consolidated																		APS Consolidated
			Three Months Ended June 30,																		Three Months Ended June 30,
			2024						2023						Net Change						2024						2023						Net Change
			(dollars in millions)
Operating revenues			$	1,309					$	1,122					$	187					$	1,309					$	1,122					$	187
Fuel and purchased power expense			(437)						(408)						(29)						(437)						(408)						(29)
Operating revenues less fuel and purchased power expenses			872						714						158						872						714						158
Operations and maintenance			(272)						(277)						5						(273)						(272)						(1)
Depreciation and amortization			(225)						(195)						(30)						(225)						(195)						(30)
Taxes other than income taxes			(59)						(58)						(1)						(59)						(58)						(1)
Pension and other postretirement non-service credits, net			13						10						3						13						11						2
Allowance for equity funds used during construction			9						13						(4)						9						13						(4)
Other income and expenses, net			—						2						(2)						—						—						—
Interest charges, net of allowance for borrowed funds used during construction			(98)						(82)						(16)						(82)						(70)						(12)
Income taxes			(32)						(16)						(16)						(39)						(20)						(19)
Less income related to noncontrolling interests			(4)						(4)						—						(4)						(4)						—
Net Income Attributable to Common Shareholders			$	204					$	107					$	97					$	212					$	119					$	93

Operating revenues less fuel and purchased power expenses. Operating revenues less fuel and purchased power expenses were $158 million higher for the three months ended June 30, 2024, compared with the prior-year period. The following table summarizes the major components of this change:

			Increase (Decrease)
			Operating revenues						Fuel and purchased power expenses						Net change
			(dollars in millions)
Impact of new rates from the 2022 Rate Case, effective March 8, 2024 (Note 4)			$	69					$	—					$	69
Effects of weather			65						20						45
Higher retail revenue due to changes in usage patterns and customer growth partially offset by the impacts of energy efficiency and related pricing			51						13						38
CRS revenue (Note 4)			12						—						12
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs			7						1						6
Lower transmission revenues (Note 4)			(7)						—						(7)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals			(7)						(4)						(3)
LFCR revenue (Note 4)			(4)						—						(4)
Miscellaneous items, net			1						(1)						2
Total			$	187					$	29					$	158

Operations and maintenance. Operations and maintenance expenses decreased $5 million for the three months ended June 30, 2024, compared with the prior-year period, primarily due to:

• A decrease of $4 million related to nuclear generation costs;

• A decrease of $4 million related to corporate resources costs;

• A decrease of $4 million related to non-nuclear generation costs, primarily due to lower operating costs;

• An increase of $4 million related to information technology costs;

• An increase of $4 million related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; and

• A decrease of $1 million for other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $30 million higher for the three months ended June 30, 2024, compared to the prior-year period, primarily due to increased plant in service and increased intangible assets.

Interest charges, net of allowance for borrowed funds and equity funds used during construction. Interest charges, net of allowance for funds used during construction, were $20 million higher for the three months ended June 30, 2024, compared to the prior-year period, primarily due to higher debt balances and higher interest rates in the current period and lower allowance for equity funds.

Income taxes. Income taxes were $16 million higher for the three months ended June 30, 2024, compared with the prior-year period, primarily due to higher pre-tax income, partially offset by the favorable timing of recognition for permanent items and credits.

Operating Results — Six-month period ended June 30, 2024, compared with six-month period ended June 30, 2023.

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2024, was $221 million, compared with consolidated net income attributable to common shareholders of $103 million for the prior-year period. The results reflect an increase of approximately $118 million, primarily as a result of the impacts of new customer rates, increased customer usage and growth, the effects of weather, higher CRS revenue, and higher other income mainly due to the gain on the sale of BCE. See Note 16. These positive factors were partially offset by higher depreciation and amortization expense mostly due to increased plant and intangible assets, higher interest charges, net of AFUDC, higher income taxes, partially offset by the favorable timing of recognition for permanent items and credits, and lower transmission revenues.

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

			Pinnacle West Consolidated																		APS Consolidated
			Six Months Ended June 30,																		Six Months Ended June 30,
			2024						2023						Net Change						2024						2023						Net Change
			(dollars in millions)
Operating revenues			$	2,261					$	2,067					$	194					$	2,261					$	2,067					$	194
Fuel and purchased power expense			(795)						(802)						7						(795)						(802)						7
Operating revenues less fuel and purchased power expenses			1,466						1,265						201						1,466						1,265						201
Operations and maintenance			(530)						(527)						(3)						(526)						(519)						(7)
Depreciation and amortization			(435)						(387)						(48)						(435)						(387)						(48)
Taxes other than income taxes			(118)						(115)						(3)						(118)						(115)						(3)
Pension and other postretirement non-service credits, net			24						20						4						25						21						4
Allowance for equity funds used during construction			19						28						(9)						19						28						(9)
Other income and expenses, net			24						2						22						3						4						(1)
Interest charges, net of allowance for borrowed funds used during construction			(184)						(157)						(27)						(156)						(134)						(22)
Income taxes			(36)						(17)						(19)						(42)						(24)						(18)
Less income related to noncontrolling interests			(9)						(9)						—						(9)						(9)						—
Net Income Attributable to Common Shareholders			$	221					$	103					$	118					$	227					$	130					$	97

Operating revenues less fuel and purchased power expenses. Operating revenues less fuel and purchased power expenses were $201 million higher for the six months ended June 30, 2024, compared with the prior-year period. The following table summarizes the major components of this change:

			Increase (Decrease)
			Operating revenues						Fuel and purchased power expenses						Net change
			(dollars in millions)
Impact of new rates from the 2022 Rate Case, effective March 8, 2024 (Note 4)			$	91					$	—					$	91
Higher retail revenue due to changes in usage patterns and customer growth partially offset by the impacts of energy efficiency and related pricing			76						25						51
Effects of weather			51						16						35
CRS revenue (Note 4)			23						—						23
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs			9						2						7
LFCR revenue (Note 4)			4						—						4
Lower transmission revenues (Note 4)			(13)						—						(13)
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals			(50)						(50)						—
Miscellaneous items, net			3						—						3
Total			$	194					$	(7)					$	201

Operations and maintenance. Operations and maintenance expenses increased $3 million for the six months ended June 30, 2024, compared with the prior-year period, primarily due to:

• An increase of $6 million related to information technology costs;

• An increase of $4 million related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

• An increase of $2 million related to employee benefit costs;

• An increase of $2 million related to transmission, distribution, and customer service costs;

• A decrease of $4 million related to corporate resources costs;

• A decrease of $3 million related to non-nuclear generation costs primarily due to lower operating costs;

• A decrease of $2 million related to nuclear generation costs;

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

Depreciation and amortization. Depreciation and amortization expenses were $48 million higher for the six months ended June 30, 2024, compared to the prior-year period, primarily due to increased plant in service and increased intangible assets.

Other income and expenses, net. Other income and expenses, net were $22 million higher for the six months ended June 30, 2024, compared to the prior-year period, primarily due to the gain on the sale of BCE. See Note 16. The difference between APS’s and Pinnacle West’s other income and expense, net is primarily related to Pinnacle West’s gain on the sale of BCE.

Interest charges, net of allowance for borrowed funds and equity funds used during construction. Interest charges, net of allowance for funds used during construction, were $36 million higher for the six months ended June 30, 2024, compared to the prior-year period, primarily due to higher debt balances and higher interest rates in the current period and lower allowance for equity funds.

Income taxes. Income taxes were $19 million higher for the six months ended June 30, 2024, compared with the prior-year period, primarily due to higher pre-tax income, partially offset by the favorable timing of recognition for permanent items and credits.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.

Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At June 30, 2024, APS’s common equity ratio, as defined, was 50%. Its total shareholder equity was approximately $7.7 billion and total capitalization was approximately $15.4 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $6.1 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

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, term loan 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.

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. On April 19, 2024, APS submitted an application to the ACC requesting to increase the long-term debt limit from $8.0 billion to $9.5 billion. APS cannot predict the outcome of this matter.

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 the ACC approved the increased equity infusion limit for 2024 on January 9, 2024 and subsequently issued the order on January 12, 2024. On April 19, 2024, APS submitted an application to the ACC requesting to increase Pinnacle West’s permitted yearly equity infusions to equal up to 2.5% of Pinnacle West’s consolidated assets each calendar year on a three-year rolling average basis. APS cannot predict the outcome of this matter.

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. See Note 3.

Summary of Cash Flows

The following tables present net cash provided by (used for) operating, investing and financing activities (dollars in millions):

Pinnacle West Consolidated

			Six Months Ended June 30,												Net
			2024						2023						Change
Net cash flow provided by operating activities			$	537					$	438					$	99
Net cash flow used for investing activities			(887)						(884)						(3)
Net cash flow provided by financing activities			349						449						(100)
Net change in cash and cash equivalents			$	(1)					$	3					$	(4)

Arizona Public Service Company

			Six Months Ended June 30,												Net
			2024						2023						Change
Net cash flow provided by operating activities			$	573					$	466					$	107
Net cash flow used for investing activities			(932)						(865)						(67)
Net cash flow provided by financing activities			358						399						(41)
Net change in cash and cash equivalents			$	(1)					$	—					$	(1)

Operating Cash Flows

Six-month period ended June 30, 2024, compared with six-month period ended June 30, 2023. Pinnacle West’s consolidated net cash provided by operating activities was $537 million in 2024, compared to $438 million in 2023, an increase of $99 million in net cash provided, primarily due to $174 million lower fuel and purchased power costs, $64 million higher cash receipts from electric revenues, $54 million lower payments for operations and maintenance costs, $18 million lower other taxes and a $10 million change in net collateral, partially offset by $145 million lower customer advances for construction, $28 million other changes in working capital, $25 million higher income taxes and $23 million higher interest payments.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. Under ERISA, the qualified pension plan was 110% funded as of January 1, 2024, and 112% as of January 1, 2023. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We have not made any voluntary contributions to our pension plan year-to-date in 2024. The minimum required cash 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 have not made a contribution year-to-date in 2024 and do not expect to make any contributions in 2024, 2025 or 2026. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 102% funded as of December 31, 2023, and our postretirement benefit plans were 162% funded, as measured for GAAP purposes at December 31, 2023. See Note 5 for additional details.

Investing Cash Flows

Six-month period ended June 30, 2024, compared with six-month period ended June 30, 2023. Pinnacle West’s consolidated net cash used for investing activities was $887 million in 2024, compared to $884 million in 2023, an increase of $3 million, primarily related to proceeds from the BCE Sale and lower BCE investment activity, partially offset by increased capital expenditures. The difference between APS’s and Pinnacle West’s net cash used for investing activities primarily relates to the BCE Sale. See Note 16 for additional details.

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

Capital Expenditures

(dollars in millions)

			Estimated for the Year Ended December 31,
			2024						2025						2026
APS
Generation:
Clean:
Nuclear Generation			$	130					$	130					$	140
Renewables and Energy Storage Systems (“ESS”) (a)			175						305						280
Other Generation (b)			455						320						235
Distribution			565						550						590
Transmission			340						415						420
Other (c)			285						280						385
Total APS			$	1,950					$	2,000					$	2,050

(a)Energy storage, renewable projects, and other clean energy projects, including the APS Solar Communities Program.

(b)Includes generation environmental projects.

(c)Primarily information systems and facilities 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 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. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

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

Financing Cash Flows and Liquidity

Six**-month period ended June 30, 2024, compared with** six**-month period ended June 30, 2023.** Pinnacle West’s consolidated net cash provided by financing activities was $349 million in 2024, compared to $449 million in 2023, a decrease of $100 million in net cash provided, primarily due to $675 million higher

long-term debt repayments, and a net increase in short-term debt repayments of $43 million, partially offset by $624 million in higher issuance of long-term debt.

APS’s consolidated net cash provided by financing activities was $358 million in 2024, compared to $399 million in 2023, a decrease of $41 million in net cash provided, primarily due to $250 million higher long-term debt repayments, $50 million in lower issuance of long-term debt, and a net increase in short-term repayments of $37 million, partially offset by $300 million higher equity infusion.

Significant Financing Activities. On June 19, 2024, the Pinnacle West Board of Directors declared a dividend of $0.88 per share of common stock, payable on September 3, 2024, to shareholders of record on August 1, 2024.

On June 12, 2024, Pinnacle West contributed $450 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

Available Credit Facilities**.** Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to finance indebtedness, and other general corporate purposes. See Note 3 for more information on available credit facilities.

Equity Forward Sale Agreements. On February 28, 2024, Pinnacle West entered into various equity forward sale agreements (the “Equity Forward Sale Agreements”), which, at the option of Pinnacle West, may be settled in shares of Pinnacle West common stock with physical or net settlement or with cash settlement. At June 30, 2024, Pinnacle West could have settled the Equity Forward Sale Agreements with physical delivery of 11,240,601 shares of common stock to the counterparties in exchange for cash of $726 million. See Note 10 for more information on the Equity Forward Sale agreements.

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

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At June 30, 2024, the ratio was approximately 61% for Pinnacle West and 51% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.

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

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to

default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

See Note 3 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of July 23, 2024, are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. On March 7, 2024, S&P affirmed the ratings and revised the Company’s and APS’s outlooks from negative to stable. On March 20, 2024, Moody’s downgraded both the Company’s and APS’s credit ratings by a notch and revised their outlooks from negative to stable. On March 26, 2024, Fitch affirmed APS’s ratings and downgraded the Company’s ratings by a notch. Fitch revised the outlook for both the Company and APS from negative to stable. At this time, we believe we have sufficient available liquidity resources to respond to a potential downward revision to our credit ratings.

			Moody’s						Standard & Poor’s						Fitch
Pinnacle West
Corporate credit rating			Baa2						BBB+						BBB
Senior unsecured			Baa2						BBB						BBB
Commercial paper			P-2						A-2						F3
Outlook			Stable						Stable						Stable
APS
Corporate credit rating			Baa1						BBB+						BBB+
Senior unsecured			Baa1						BBB+						A-
Commercial paper			P-2						A-2						F2
Outlook			Stable						Stable						Stable

Contractual Obligations

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

• Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at June 30, 2024. See Note 3.

• Pinnacle West and APS maintain committed revolving credit facilities. See Note 3 for short-term debt details.

• Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. Purchase obligations include capital expenditures and other obligations. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Notes 4 and 8.

• APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 4 and 8.

• APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 6.

• APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation. See Note 8.

• The Equity Forward Sale Agreements, which may be settled by Pinnacle West with common stock or cash. Pinnacle West has classified the agreements as an equity transaction in accordance with GAAP. See Note 10.

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. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. There have been no changes to our critical accounting policies and estimates since our 2023 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2023 Form 10-K for further details about our critical accounting policies and estimates.

MARKET AND CREDIT RISKS

Market Risks

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

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Notes 11 and 12), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning, coal reclamation, and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

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

			Six Months Ended June 30,
			2024						2023
Mark-to-market of net positions at beginning of period			$	(120)					$	96
Increase in regulatory asset			(2)						(163)
Mark-to-market of net positions at end of period			$	(122)					$	(67)

The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at June 30, 2024, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements” in Item 8 of our 2023 Form 10-K and Note 11 for more discussion of our valuation methods.

Source of Fair Value						2024						2025						2026						2027						2028						Total Fair Value
Observable prices provided by other external sources						$	(53)					$	(42)					$	(6)					$	—					$	—					$	(101)
Prices based on unobservable inputs						(16)						(3)						(2)						—						—						(21)
Total by maturity						$	(69)					$	(45)					$	(8)					$	—					$	—					$	(122)

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets (dollars in millions):

			June 30, 2024												December 31, 2023
			Gain (Loss)												Gain (Loss)
			Price Up 10%						Price Down 10%						Price Up 10%						Price Down 10%
Mark-to-market changes reported in:
Regulatory asset (liability) (a)
Electricity			$	11					$	(11)					$	9					$	(9)
Natural gas			59						(59)						55						(55)
Total			$	70					$	(70)					$	64					$	(64)

(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 7 for a discussion of our credit valuation adjustment policy.