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 2022 Form 10-K and Part II, Item 1A of this report.

OVERVIEW

Business Overview

Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $24 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.

Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS. APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.4 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.

Inflation

Overall inflation has grown by 4.4% in Phoenix over the past twelve months to June 2023, compared to 3% 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. Sharp price increases have begun to level off from the heightened market in the fourth quarter 2022; however, APS has continued to see increases of up to 20% in the second quarter of 2023. APS has seen inflationary impacts in volatile spend categories such as fuel, chemicals, and electrical components impacted by manufacturing capacity constraints. Inflation has also impacted spend categories through pass-through costs such as supplier’s increased material costs, cost of insurance, and wage rates.

Even prior to these increases, APS has focused on its customer affordability initiative, which has enabled APS to mitigate against 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 against several procurement spend areas such as transformers.

Inflation Reduction Act of 2022

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”). The IRA significantly expands the availability of tax credits for investments in clean energy generation technologies and energy storage. Key provisions that are relevant to the Company’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a

Production Tax Credit (“PTC”) in lieu of the Investment Tax Credit (“ITC”) beginning in 2022; (ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023; and (iii) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants, available from 2024 through 2032. The Internal Revenue Service and U.S. Treasury continue to issue regulations and other guidance which will provide additional details and clarifications regarding how the Company may be able to claim each of these credits.

In addition, the IRA contains several provisions which could create additional tax liabilities for corporations, including a 15% corporate alternative minimum tax for corporations with net profits in excess of $1 billion and a 1% excise tax on stock buybacks. We currently do not believe the Company will be subject to any material tax liabilities as a result of these legislative provisions.

COVID-19

During the COVID-19 pandemic, APS experienced some delays in finished materials and a tight labor market. APS has measures in place to continually monitor and evaluate resource and labor needs and supply chain adequacy but cannot predict whether there will be material supply chain or labor shortages in the future as a result of COVID-19, another pandemic, or otherwise. APS also 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.

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.

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.

Strategic Overview

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

Clean Energy Commitment

We are committed to doing our part to make the future clean and carbon-free. As Arizona stewards, we do what is right for the people and prosperity of Arizona. Our vision is to create a sustainable energy future for Arizona through providing clean, affordable, and reliable energy. We can accomplish our visions through collaboration with customers, communities, employees, policymakers, shareholders, and other stakeholders. Our clean energy goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.

APS’s clean energy goals consist of three parts:

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

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

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

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

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

2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix, which includes all carbon-free resources like nuclear, 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 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 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 planned exits from Four Corners and Cholla, along with the prior closure of the Navajo Plant. All ordered payments and expenditures would be recoverable through rates. See Note 4 for a discussion of the CCT plan.

Consistent with the 2019 Rate Case decision, as of April 2023, APS has completed the following payments that will be recoverable through rates related to the CCT: (i) $6.66 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) $1 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 authorized $1.25 million to be recovered through rates for electrification of homes and businesses on both the Navajo Nation and Hopi reservations. To support the expenditure of the recoverable funds for electrification of homes and businesses on the Navajo Nation and the Hopi reservations, a census was conducted of the unelectrified homes and businesses in each that are also within APS service territory. The census work was fully completed in November 2022, and discussions regarding the use of the $1.25 million for electrification of homes and businesses on both the Navajo Nation and Hopi reservations are ongoing.

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, and on April 17, 2023, the ACC closed the docket. Any further action on CCT issues will take place in utility rate cases, including the currently pending 2022 Rate Case. APS cannot predict the outcome of this matter.

In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners beginning in fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership. Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring. The other unit would remain online year-round, subject to market conditions as well as planned maintenance outages and unplanned outages. As of the date of this report, APS anticipates that it will elect not to begin seasonal operation in November 2023, unless market conditions change.

Renewables. APS’s IRP (see Note 4 for additional information) establishes the path to meeting our clean energy commitment and maintaining reliable electric service for our customers. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Our IRP rapidly adds clean energy and storage resources while maintaining reliable and affordable service. 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, 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. This balance will ensure an appropriately diverse portfolio designed to achieve the same operational reliability and customer affordability as APS’s near-term strategies. In addition, APS is actively seeking to include future facility purchase options in its PPAs that will enable investments with greater financial flexibility.

APS uses competitive “all source” RFPs to pursue market 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. Available projects are guided by IRP timelines and quantities and APS maintains a flexible approach that allows it to optimize system reliability and customer affordability through the RFP process. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid.

In December 2020, APS issued two RFPs: (i) a battery storage RFP for projects to be located at two AZ Sun sites, and (ii) an all-source RFP that solicited resources to meet our clean energy needs and capacity to maintain system reliability, and was later amended to include a request for 150 MW of solar resources to be developed on APS property and owned by APS (collectively, the “December 2020 RFPs”). As a result of the December 2020 RFPs, APS executed two solar plus storage PPAs totaling 275 combined MW, a PPA for a 238 MW wind resource, and 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 2023.

In May 2022, APS issued an all-source RFP to address resource needs for 2025 and beyond (“2022 RFP”). The 2022 RFP solicited 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 June 30, 2023, APS has signed four solar plus energy storage PPAs totaling 840 MW of solar resources, paired with approximately 881 MW of energy storage resources, another 555 MW of stand-alone energy storage, and a PPA for 216 MW of wind resources. In addition to the renewable resources described above, the 2022 RFP also resulted in the extension of tolls at two merchant gas facilities.

On June 30, 2023, APS issued an all-source 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 are due September 1, 2023, and APS plans to execute agreements starting in fall 2023 through spring 2024.

The following table summarizes the resources in APS’s renewable energy portfolio that are in operation or under development as of June 30, 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 (MW)						Net Capacity Planned / Under Development (MW)
Total APS Owned: Solar			265						150			(b)
Purchased Power Agreements Renewables:
Solar			310						1,275
Wind			637						216
Geothermal			10						—
Biomass			14						—
Biogas			3						—
Total Purchased Power Agreements			974						1,491
Total Distributed Energy: Solar (a)			1,527						100			(c)
Total Renewable Portfolio			2,766						1,741

(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) Includes 150 MW of capacity that was mechanically completed in June 2023 but has not yet entered commercial operation.

(c) 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.

In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. 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 completes the addition of storage on current APS-owned utility-scale solar facilities. These battery storage facilities are currently expected to be in service during the first through third quarters of 2023. As of May 2, 2023, the 141 MW of the initial phase of battery deployment at AZ Sun sites has entered into service.

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 Power Supply Adjustment (“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. APS since terminated one energy storage PPA totaling 200 MW due to project delays. Service under the remaining agreements is expected to begin in 2023 and 2024.

Following the 2022 RFP, as of June 30, 2023, APS has executed four 20-year PPAs for solar plus storage resources totaling 840 MW of solar resources, paired with approximately 881 MW of energy storage resources, and another three 20-year PPAs for stand-alone energy storage resources totaling 555 MW. The PPAs are subject to ACC approval to enable cost recovery through the PSA. As of June 30, 2023, four of these agreements have received approval to be recovered through the PSA and the other three will be heard in future ACC Open Meetings. Service under these agreements are expected to begin in 2025.

APS currently plans to install more than 2,100 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs.

The following table summarizes the resources in APS’s energy storage portfolio that are in operation or under development as of June 30, 2023. 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			141						60(b)
Purchase Power Agreements - Energy Storage			—						1,961
Residential Energy Storage			24(a)						4
Total Energy Storage Portfolio			165						2,025

(a) Includes 23.9 MW of APS customer-owned batteries and 0.3 MW of APS-owned residential batteries.

(b) Includes 60 MW of capacity that was mechanically completed in June 2023 but has not yet entered commercial operation.

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 southwest 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.

Affordable

Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and achieving internal efficiencies. APS continues to drive this initiative by identifying opportunities to streamline its business processes to assist in mitigating cost increases, increasing employee retention, and improving customer satisfaction.

Participation in the Energy Imbalance Market (“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.

Reliable

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 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 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 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.

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 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 APS ended 2022 as one of the most improved utilities in the nation for both residential and business customer satisfaction. Residential customer satisfaction finished 2022 ranked in the second quartile among large investor-owned utilities, and business customer satisfaction ranked in the first quartile of utilities nationally.

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 June 2023, APS had installed 704 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 charging stations, which are open for public use, are located in Show Low, Sedona, Prescott, Globe, and Payson, Arizona. Each location features two 150 kilowatt and two 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 filed its required TE progress report on March 15 and will file its next required progress report on September 15, 2023. In accordance with an extension granted by the ACC, APS intends to file a 2024 TE Plan by November 30, 2023.

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. Palo Verde has completed the required reports for these projects and has submitted, or soon will submit, the reports via Energy Harbor and Xcel to the DOE. Due to other needs for Palo Verde personnel and related resources, the submission of the reports will complete Palo Verde’s role in these projects.

The Southwest Clean Hydrogen Innovation Network (“SHINe”) regional hub was formed due to the Infrastructure Investment and Jobs Act (“IIJA”), also known as the Bipartisan Infrastructure Bill, which 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, 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 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, which also includes projects in Nevada. On December 27, 2022, the SHINe regional hub was one of thirty-three regional hubs encouraged to submit a full application by the DOE. SHINe’s full application was submitted to the DOE on April 7, 2023. APS is currently maintaining a participatory role in AzCaNE, but APS’s role, if any, in the SHINe regional hub has yet to be determined.

Carbon Capture

Carbon capture technologies can isolate CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. APS will continue to monitor this emerging technology, particularly in regard to EPA’s proposed GHG rule. On May 24, 2023, the EPA proposed regulations for GHG emissions that would, among other things, require carbon capture technologies for certain classifications of coal-, oil-, and natural gas-fired electricity generating units. See Note 8 for more information. APS cannot predict the outcome of this proposed rule.

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

Pinnacle West has been integrating ESG practices into its core work for almost 30 years. As a business strategy, we seek solutions that provide “shared value,” meaning solutions that address societal and environmental challenges in a way that also delivers business value. Our commitment extends beyond implementing sustainability practices; we are dedicated to working with our stakeholders to identify and address the sustainability issues that we are uniquely positioned to impact through our business. In 2020, in support of our clean energy commitment and the growing focus on ESG within our organization, we increased our efforts by dedicating a new Sustainability Department at Pinnacle West to integrating ESG best practices into the everyday work of the Company.

As a first step, the Company engaged the Electric Power Research Institute (“EPRI”) and leveraged input from employees, large customers, limited-income advocates, economic development groups, environmental non-governmental organizations, leading sustainability academics and other stakeholders to identify and assess the sustainability issues that matter most. In total, 23 Priority Sustainability Issues (“PSIs”) were identified and prioritized. The most critical category, Integral Shared Value, includes four issues deemed most important and most able to be impacted by our actions: clean energy, customer experience, energy access and reliability and safety and health. These Integral PSIs provide the foundation for informing our strategic direction, creating a framework for incorporating best practices and driving enterprise-wide alignment and accountability. In 2021, the Company engaged EPRI for the second phase of this work, focused on benchmarking best practices within these four Integral Shared Value PSIs. We 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. The ESG Strategic Framework has guided our ESG activities, allowing the Sustainability Department to prioritize projects and collaborate with our teams in the Company. The Company also developed an ESG Narrative, aligned to the APS Promise, to guide the Company’s communications strategy internally and externally to customers to effectively share APS’s sustainability story.

Regulatory Overview

2022 Retail Rate Case

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

The principal provisions of APS’s application are:

• a test year comprised of 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 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 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 are:

• reducing the revenue requirement increase to $383.1 million;

• 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.

APS’s rejoinder testimony is due on August 4, 2023.

APS requested that the increase become effective December 1, 2023. The hearing for this rate case is currently scheduled to begin in August 2023. APS cannot predict the outcome of its request.

2019 Retail Rate Case

On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) seeking an increase in annual retail base rates. On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. See Note 4 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%, which includes a 20-basis point penalty, (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. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended.

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

Additionally, consistent with the 2019 Rate Case decision, as of July 2023, APS completed the following payments that will be recoverable through rates related to the CCT: (i) $6.66 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) $1 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 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, among other things. 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. On March 6, 2023, the Court issued its opinion in this matter, affirming in part and reversing in part the ACC’s decision in the 2019 Rate Case. The Court vacated the 20-basis-point penalty included in the ACC’s allowed return on equity, as the Court determined the use of customer service metrics to justify the reduction exceeded the ACC’s ratemaking authority. Additionally, the Court vacated the disallowance of $215.5 million of APS’s Four Corners SCR investment. The Court remanded the issue to the ACC for further proceedings. The ACC requested an extension of the 30-day deadline to appeal the matter to the Arizona Supreme Court, and the Arizona Supreme Court granted the extension of the deadline to May 8, 2023. The ACC filed an appeal on May 8, 2023, and on May 15, 2023, requested a suspension of the case to allow for settlement discussions between the parties, which was approved by the Court.

On June 14, 2023, APS and the ACC Legal Division filed a joint resolution to allow recovery of the $215.5 million in costs related to the installation of the Four Corners SCR, 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. On June 21, 2023, the ACC approved the joint resolution, and the proposals in the joint resolution became effective on July 1, 2023. On July 18, 2023, the Sierra Club filed an application for rehearing of the Commission’s decision. If the Commission does not grant the application within 20 days, it will be deemed denied. The Sierra Club will have 30 days after resolution of its request for rehearing to file a notice of appeal to Arizona Court of Appeals.

See Note 4 for information regarding additional regulatory matters.

Four Corners SCR Cost Recovery

As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On 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. On March 6, 2023, the Court of Appeals issued its opinion in the matter, vacating the ACC’s

disallowance of the SCR investment and remanding the matter back to the ACC for further review in accordance with ACC rule and the order of the Court of Appeals. On June 21, 2023, the ACC approved a joint settlement filed by APS and the ACC’s Legal Division that resolved all issues relating to the 2019 Rate Case decision, including recovery of the cost of the Four Corners SCRs. See above for further discussion on the 2019 Rate Case decision. See Note 4 for additional information regarding the Four Corners SCR cost recovery.

Financial Strength and Flexibility

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

Other Subsidiaries

Bright Canyon Energy*.* On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry. As of June 30, 2023, BCE had total assets of approximately $128 million.

In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 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. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms. Clear Creek achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under long-term 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 granted in part and denied in part on December 16, 2021. Tenaska Clear Creek Wind, LLC filed a request for rehearing, 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. FERC denied the request for rehearing and the motion for stay with substantive discussion in an order issued on February 16, 2023. Tenaska Clear Creek Wind, LLC, has filed Petitions for Review of the relevant orders with the U.S. Court of Appeals for the D.C. Circuit, which are still pending. Tenaska Clear Creek Wind, LLC filed its opening brief on June 30, 2023.

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. The request for rehearing was denied by FERC with substantive discussion in an order issued on April 20, 2023. Tenaska Clear Creek Wind, LLC has filed Petitions for Review of the relevant orders with the U.S. Court of Appeals for the D.C. Circuit, which are still pending.

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 ongoing 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 included an after-tax loss of $12.8 million relating to this impairment.

BCE has started construction on a microgrid facility in Los Alamitos, California (“Los Alamitos”) 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 3 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. On April 18, 2023, the Kūpono Solar special purpose entity, entered into a $140 million non-recourse construction financing agreement. The construction financing will convert into a sale leaseback agreement upon commercial operation of the project. The financing agreement requires $40 million of sponsor equity, which has been funded by the project’s equity participants. In connection with the financing, Pinnacle West has issued performance guarantees relating to the project.

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 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 June 30, 2023, El Dorado has contributed approximately $14.6 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 June 30, 2023, El Dorado has contributed approximately $4.0 million to AZ-VC. The remainder of the investment will be contributed by El Dorado as investments are selected by AZ-VC.

Key Financial Drivers

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 2020 through 2022, retail electric revenues comprised approximately 92% 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, 2023, compared with the prior-year period. For the three years through 2022, APS’s customer growth averaged 2.2% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2023 and the average annual growth to be in the range of 1.5% to 2.5% through 2025 based on anticipated steady population growth in Arizona during that period.

Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.7% for the six-month period ended June 30, 2023, compared with the prior-year period. While steady customer growth was somewhat offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong sales to commercial and industrial customers and the ramp-up of new data center customers.

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. 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.

For the three years through 2022, annual retail electricity sales growth averaged 2.5%, 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 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. Lower projected sales growth for 2023 compared to our prior update is primarily due to slower-than-expected growth in new data center customers and delays among several new, large manufacturing facilities.

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 their future extra-large projects (over 25 MW) and that APS is exploring available options for securing sufficient electric generation and transmission to meet these projections of future customer needs.

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 offset by the same amount of operating revenues) and other factors.

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

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.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.2% of the assessed value for 2022, 10.7% for 2021, and 10.8% for 2020. Property taxes decreased in 2022 due to 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 legislative changes noted above.

Income Taxes**.** Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions, and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax 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. 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 in commercial operation.

RESULTS OF OPERATIONS

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

Operating Results — Three-month period ended June 30, 2023, compared with three-month period ended June 30, 2022.

Our consolidated net income attributable to common shareholders for the three months ended June 30, 2023, was $107 million, compared with consolidated net income attributable to common shareholders of $164 million for the prior-year period. The results reflect a decrease of approximately $58 million for the regulated electricity segment, primarily as a result of higher operations and maintenance expense, higher interest charges, lower pension and other postretirement non-service credits, and higher depreciation and amortization expense, mostly due to increased plant assets. These negative factors were partially offset by higher transmission and LFCR revenue, less the effects of weather, and lower income taxes.

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

			Three Months Ended June 30,
			2023						2022						Net Change
			(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses			$	713					$	708					$	5
Operations and maintenance			(276)						(244)						(32)
Depreciation and amortization			(195)						(186)						(9)
Taxes other than income taxes			(58)						(54)						(4)
Pension and other postretirement non-service credits - net			10						25						(15)
All other income and expenses, net			16						10						6
Interest charges, net of allowance for borrowed funds used during construction			(82)						(62)						(20)
Income taxes			(16)						(27)						11
Less income related to noncontrolling interests (Note 6)			(4)						(4)						—
Regulated electricity segment income/(loss)			108						166						(58)
All other			(1)						(2)						1
Net Income Attributable to Common Shareholders			$	107					$	164					$	(57)

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $5 million higher for the three months ended June 30, 2023, compared with the prior-year period. The following table summarizes the major components of this change:

			Increase (Decrease)
			Operating revenues						Fuel and purchased power expenses						Net change
			(dollars in millions)
Higher transmission revenues (Note 4)			$	17					$	—					$	17
LFCR revenue (Note 4)			16						—						16
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs			2						(4)						6
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals			77						73						4
Effects of weather			(51)						(13)						(38)
Total			$	61					$	56					$	5

Operations and maintenance. Operations and maintenance expenses increased $32 million for the three months ended June 30, 2023, compared with the prior-year period primarily because of:

• An increase of $10 million related to non-nuclear generation costs primarily due to higher operating costs and higher planned outages;

• An increase of $10 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

• An increase of $7 million related to transmission, distribution, and customer service;

• An increase of $5 million in nuclear generation costs;

• An increase of $2 million related to information technology costs;

• A decrease of $4 million related to employee benefits; and

• An increase of $2 million for corporate resources and other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $9 million higher for the three months ended June 30, 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 three months ended June 30, 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. Other income and expenses, net were $6 million higher for the three months ended June 30, 2023, compared to the prior-year period primarily due to higher interest income and higher allowance for equity funds used during construction due to increased capital expenditures.

Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $20 million higher for the three months ended June 30, 2023, compared to the prior-year period primarily due to higher debt balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.

Income taxes. Income taxes were $11 million lower for the three months ended June 30, 2023, compared with the prior-year period primarily due to lower pre-tax income, partially offset by higher tax expense due to the timing of when permanent tax items and credits are recognized through the effective tax rate.

Operating Results — Six-month period ended June 30, 2023, compared with six-month period ended June 30, 2022.

Our consolidated net income attributable to common shareholders for the six months ended June 30, 2023, was $103 million, compared with consolidated net income attributable to common shareholders of $181 million for the prior-year period. The results reflect a decrease of approximately $76 million for the regulated electricity segment, primarily as a result of higher operations and maintenance expense, higher interest charges, lower pension and other postretirement non-service credits, and higher depreciation and amortization expense, mostly due to increased plant assets. These negative factors were partially offset by higher LFCR and transmission revenue, less the effects of weather, higher other income, and lower income taxes.

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

			Six Months Ended June 30,
			2023						2022						Net Change
			(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased power expenses			$	1,263					$	1,225					$	38
Operations and maintenance			(524)						(462)						(62)
Depreciation and amortization			(387)						(373)						(14)
Taxes other than income taxes			(115)						(112)						(3)
Pension and other postretirement non-service credits - net			20						49						(29)
All other income and expenses, net			34						20						14
Interest charges, net of allowance for borrowed funds used during construction			(157)						(123)						(34)
Income taxes			(17)						(31)						14
Less income related to noncontrolling interests (Note 6)			(9)						(9)						—
Regulated electricity segment income			108						184						(76)
All other			(5)						(3)						(2)
Net Income Attributable to Common Shareholders			$	103					$	181					$	(78)

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $38 million higher for the six months ended June 30, 2023, 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)
LFCR revenue (Note 4)			$	19					$	—					$	19
Higher transmission revenues (Note 4)			16						—						16
Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs			9						(5)						14
Higher retail revenue due to customer growth and changes in customer usage patterns, partially offset by the impacts of energy efficiency and distributed generation			16						7						9
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals			195						191						4
Effects of weather			(33)						(8)						(25)
Miscellaneous items, net			1						—						1
Total			$	223					$	185					$	38

Operations and maintenance. Operations and maintenance expenses increased $62 million for the six months ended June 30, 2023, compared with the prior-year period primarily because of:

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

• An increase of $19 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;

• An increase of $10 million related to nuclear generation costs;

• An increase of $8 million related to transmission, distribution, and customer service;

• An increase of $7 million related to information technology costs;

• A decrease of $11 million related to employee benefits; and

• An increase of $7 million for corporate resources and other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $14 million higher for the six months ended June 30, 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 $29 million lower for the six months ended June 30, 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. Other income and expenses, net were $14 million higher for the six months ended June 30, 2023, compared to the prior-year period primarily due to higher interest income and higher allowance for equity funds used during construction due to increased capital expenditures.

Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $34 million higher for the six months ended June 30, 2023, compared to the prior-year period primarily due to higher debt balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures.

Income taxes. Income taxes were $14 million lower for the six months ended June 30, 2023, compared with the prior-year period primarily due to lower pre-tax income, partially offset by higher tax expense due to the timing of when permanent tax items and credits are recognized through the effective tax rate.

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, 2023, APS’s common equity ratio, as defined, was 48%. Its total shareholder equity was approximately $7.0 billion and total capitalization was approximately $14.5 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $5.8 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 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 financing and equity infusions from Pinnacle West.

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
			2023						2022						Change
Net cash flow provided by operating activities			$	438					$	588					$	(150)
Net cash flow used for investing activities			(884)						(794)						(90)
Net cash flow provided by financing activities			449						225						224
Net change in cash and cash equivalents			$	3					$	19					$	(16)

Arizona Public Service Company

			Six Months Ended June 30,												Net
			2023						2022						Change
Net cash flow provided by operating activities			$	465					$	600					$	(135)
Net cash flow used for investing activities			(865)						(765)						(100)
Net cash flow provided by financing activities			400						184						216
Net change in cash and cash equivalents			$	—					$	19					$	(19)

Operating Cash Flows

Six-month period ended June 30, 2023, compared with six-month period ended June 30, 2022. Pinnacle West’s consolidated net cash provided by operating activities was $438 million in 2023, compared to $588 million in 2022, a decrease of $150 million in net cash provided primarily due to $270 million higher fuel and purchased power costs, $131 million higher payments for operations and maintenance costs, $40 million change in net collateral, $34 million higher interest payments and $12 million higher other taxes, partially offset by $251 million higher cash receipts from electric revenues, $35 million higher customer advances for construction and $51 million other changes in working capital.

Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. 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 112% funded as of January 1, 2023, and 139% as of January 1, 2022. 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 2023. The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2023, 2024 or 2025. With regard to contributions to our other postretirement benefit plan, we have not made a contribution year-to-date in 2023 and do not expect to make any contributions in 2023, 2024 or 2025. 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 106% funded as of December 31, 2022, and our postretirement benefit plans were 159% funded, as measured for GAAP purposes at December 31, 2022. See Note 5 for additional details.

The 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.

Investing Cash Flows

Six-month period ended June 30, 2023, compared with six-month period ended June 30, 2022. Pinnacle West’s consolidated net cash used for investing activities was $884 million in 2023, compared to $794 million in 2022, an increase of $90 million primarily related to increased capital expenditures.

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

Capital Expenditures

(dollars in millions)

			2023						2024						2025
APS
Generation:
Clean:
Nuclear Generation			$	120					$	120					$	120
Renewables and Energy Storage Systems (“ESS”) (a)			240						345						400
Other Generation (b)			265						245						245
Distribution			520						530						530
Transmission			260						300						300
Other (c)			265						260						255
Total APS			$	1,670					$	1,800					$	1,850

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

(b)Includes generation environmental projects.

(c)Primarily information systems and facilities projects.

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

Generation capital expenditures are comprised of various additions and improvements to APS’s

clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers, and environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

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, 2023, compared with six-month period ended June 30, 2022. Pinnacle West’s consolidated net cash provided by financing activities was $449 million in 2023, compared to $225 million in 2022, an increase of $224 million in net cash provided primarily due to $363 million in higher issuance of long-term debt and $150 million lower long-term debt repayments, partially offset by a net decrease in short-term borrowings of $284 million.

APS’s consolidated net cash provided by financing activities was $400 million in 2023, compared to $184 million in 2022, an increase of $216 million in net cash provided primarily due to $496 million in higher issuance of long-term debt, partially offset by a net decrease in short-term borrowings of $276 million.

Significant Financing Activities. On June 21, 2023, the Pinnacle West Board of Directors declared a dividend of $0.865 per share of common stock, payable on September 1, 2023, to shareholders of record on August 1, 2023.

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.

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, 2023, the ratio was approximately 60% for Pinnacle West and 52% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.

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

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

would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

On December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit, 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 further 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 3 for further discussions of liquidity matters.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of July 27, 2023, 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. 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			Baa1						BBB+						BBB+
Senior unsecured			Baa1						BBB						BBB+
Commercial paper			P-2						A-2						F2
Outlook			Negative						Negative						Negative
APS
Corporate credit rating			A3						BBB+						BBB+
Senior unsecured			A3						BBB+						A-
Commercial paper			P-2						A-2						F2
Outlook			Negative						Negative						Negative

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, 2023. 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. See Notes 4 and 8. Purchase obligations includes capital expenditures and other obligations. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 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.

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 2022 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2022 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 trusts, other special use funds (see Notes 11 and 12), and benefit plan assets. The nuclear decommissioning trusts, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

Commodity Price Risk

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

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

			Six Months Ended June 30,
			2023						2022
Mark-to-market of net positions at beginning of period			$	96					$	107
Increase (decrease) in regulatory liability			(163)						179
Mark-to-market of net positions at end of period			$	(67)					$	286

The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at June 30, 2023, 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 2022 Form 10-K and Note 11 for more discussion of our valuation methods.

Source of Fair Value						2023						2024						2025						2026						2027						Total Fair Value
Observable prices provided by other external sources						$	(46)					$	(10)					$	(9)					$	(1)					$	—					$	(66)
Prices based on unobservable inputs						(10)						9						—						—						—						(1)
Total by maturity						$	(56)					$	(1)					$	(9)					$	(1)					$	—					$	(67)

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, 2023												December 31, 2022
			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			$	10					$	(10)					$	12					$	(12)
Natural gas			52						(52)						55						(55)
Total			$	62					$	(62)					$	67					$	(67)

(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.