# PINNACLE WEST CAPITAL CORP (PNW) FY 2023 MD&A Verbatim Item 7 Management's Discussion and Analysis from PINNACLE WEST CAPITAL CORP's 10-K for fiscal year 2023. SEC filing source: https://www.sec.gov/Archives/edgar/data/764622/000076462224000016/pnw-20231231.htm Accession: 0000764622-24-000016 Filing date: 2024-02-27 Report date: 2023-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Company profile: /company/PNW/ All MD&A years: /company/PNW/mda/ Previous year: /company/PNW/mda/fy2022/ (FY 2022) Next year: /company/PNW/mda/fy2024/ (FY 2024) ITEM 7.  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 Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. This discussion provides a comparison of the 2023 results with 2022 results. For the discussion of 2022 compared to 2021, see Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of Pinnacle West Capital Corporation’s Annual Report on Form 10-K for the year ended December 31, 2022, which specific discussion is incorporated herein by reference. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A. OVERVIEW Business Overview Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of approximately $25 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona. 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 southwestern United States. 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 APS’s clean energy commitment include (i) an extension of tax credits for solar and wind generation, including a new option for solar investments to claim a Production Tax Credit (“PTC”) in lieu of the Investment Tax Credit (“ITC”) beginning in 2022; (ii) expansion of the ITC to cover stand-alone energy storage technology beginning in 2023; and (iii) introduction of a new PTC for nuclear energy produced by existing nuclear energy plants (“Nuclear PTC”), available from 2024 through 2032. The Internal Revenue Service and U.S. Treasury have issued preliminary guidance related to various provisions of the IRA that have enabled APS to claim credits related to its 2023 solar and battery investments. The Company continues to await regulations and other guidance, including with respect to the Nuclear PTC, which will provide additional details and clarifications regarding how the Company may be able to claim IRA tax credits in future years. In addition, the IRA contains several provisions which could create additional tax liabilities for corporations, including a 15% corporate alternative minimum tax for corporations with net profits in excess of $1 billion and a 1% excise tax on stock buybacks. We currently do not believe the Company will be subject to any material tax liabilities as a result of these legislative provisions. 57 Table of Contents Strategic Overview Our strategy is to create a sustainable energy future for Arizona that delivers shareholder value and shared value by serving our customers with reliable, affordable, and clean energy. Customer-Focused Recognizing that creating customer value is inextricably linked to increasing shareholder value, APS’s focus remains on its customers and the communities it serves. Accordingly, it is APS’s goal to achieve an industry-leading, best-in-class customer experience, while demonstrating compassion and advocacy for its customers. This multi-year objective includes incrementally improving APS’s J.D. Power (“JDP”) overall customer satisfaction ratings to achieve a first quartile ranking in its peer set comprised of large investor-owned utilities. APS has made noteworthy progress on that front. As previously disclosed, APS’s JDP Residential rankings for overall customer satisfaction improved in each of 2020, 2021, and 2022, and have improved again in 2023. At the end of 2023, APS’s residential customer satisfaction ranked in the second quartile among large investor-owned utilities, and its business customer satisfaction ranked in the second quartile of utilities nationally. Reliable While our energy mix evolves, APS’s obligation to deliver reliable service to our customers remains. APS is managing through significant growth in the Phoenix metropolitan area while experiencing supply chain issues similar to other industries. Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth, and enabling more renewable energy resources. To prioritize reliability and meet substantial growth in residential and commercial energy needs, APS has developed a future-focused, strategic transmission plan. This Ten-Year Plan includes five critical transmission projects that comprise the APS strategic transmission portfolio, which represents a significant upgrade to APS’s transmission system. These five projects, along with other projects included in the Ten-Year Plan, are intended to support growing energy needs, strengthen reliability, and allow for the connection of new resources. Our advanced distribution management system allows operators to locate outages and control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system will also integrate a new meter data management system that will increase grid visibility and give customers access to more of their energy usage data. Wildfire safety remains a critical focus for APS and other utilities. We have increased investment in fire mitigation efforts to clear defensible space around our infrastructure, continue ongoing system upgrades, build partnerships with government entities and first responders and educate customers and communities. We also increased spend on mitigating the risk associated with trees that could cause hazards, resulting in more of these trees being removed before they could cause outages or wildfires. These programs contribute to customer reliability, responsible forest management and safe communities. With recent wildfire events in Hawaii and across North America, we have been devoting and will continue to devote substantial efforts to analyzing and developing enhancements to our systems and processes to mitigate fire risk within our service territory and communities, including by hardening our infrastructure, deploying new technologies where appropriate, increasing our awareness, implementing operational 58 Table of Contents changes, and enhancing our wildfire response capabilities. APS completed implementation of best-in-class fire modelling software that we are utilizing to more surgically identify and calculate risk and target future system improvement investments such as fire-resistant pole wrapping, wood to steel pole conversions, and additional remote-controllable field devices like reclosers and switches. APS also currently intends to implement a public safety power shutoff (“PSPS”) program for this upcoming fire season, leveraging the additional real-time analysis provided by the new modelling software. We continue to evaluate policy and regulatory options, as well as insurance programs, to mitigate the impact of wildfire events. Maintaining reliability and affordability for our customers during the clean energy transition is fundamental to our strategy. As a critical partner to the large quantity of renewables and energy storage we are adding to our system, natural gas generation will play an important role in maintaining reliability for our customers. One example is the 2019 addition of new natural gas units at the modernized Ocotillo Power Plant to provide cleaner-running and more efficient units. Additionally, efficiency improvements to gas units at the Redhawk and Sundance Power Plants are planned for completion prior to the summer of 2024. As part of a balanced energy portfolio, these flexible resource additions support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening when solar production declines as the sun sets and customer demand peaks. Complementary to and in support of the transition to renewable resources, APS continues to evaluate options to meet growing energy demand and ensure grid reliability, including through upgrades to and/or modernization of additional existing natural gas facilities. In October 2021, APS announced plans to evaluate regional market solutions as part of the informal Western Markets Exploratory Group (“WMEG”). As a member of WMEG, APS is exploring the potential for a staged approach to new market services, including day-ahead energy sales, transmission system expansion, and other power supply and grid solutions consistent with existing state regulations. WMEG hopes to identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers. APS is unable to predict the outcome of these discussions. APS will go live with a new Energy Management System (“EMS”) in March of 2024. The new EMS will better allow for integration of the renewable and energy storage assets into the APS’s generation resources. This integration will allow APS to maximize the flexibility of our resources and fully engage in the Energy Imbalance Market. It also better positions APS to participate in market opportunities that may develop through the next decade. APS’s key elements to delivering reliable power include resource planning, sufficient reserve margins, customer partnerships to manage peak demand, fire mitigation, and operational preparedness. Seasonal readiness procedures at APS also include inspections to ensure good material conditions and critical control system surveys. APS also plans for the unexpected by conducting emergency operations drills and coordinating on fire and emergency management with federal, state, and local agencies. Affordable APS continues to focus on mitigating the cost pressures related to the current inflationary environment. Overall inflation grew by 2.7% in Phoenix and 3.4% nationally during 2023. In 2022, overall inflation grew by 9.5% in Phoenix and 6.5% nationally. The impacts from inflation have varied across separate categories of APS’s spending, including increases of up to 15% in 2023. APS has seen inflationary impacts in supply constrained categories related to electrical equipment, such as transformers, 59 Table of Contents wire, and cable impacted by high utility demand outpacing manufacturing capacity. Inflation continues to impact service rates and spend categories through pass-through costs such as supplier’s increased material costs, cost of insurance, and wage rates. APS’s customer affordability initiative includes internal opportunities, such as training and mentoring employees on identifying efficiency opportunities; maintaining an inventory to take advantage of lower pricing and avoid expediting fees; entering into long-term contracts to hedge against price volatility, which has allowed APS to mitigate against procurement spend areas such as transformers; and implementing automation technologies to enhance efficiencies and increase data-oriented decision making. There are also external opportunities under APS’s customer affordability initiative, such as APS’s participation in the Western Energy Imbalance Market (“WEIM”). WEIM continues to be a tool for creating savings for APS’s customers from the real-time, voluntary market. APS continues to expect that its participation in WEIM will lower its fuel and purchased-power costs, improve situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources. APS is participating in market design and tariff development of Markets+, a day-ahead and real-time market offering from Southwest Power Pool. APS also participated in the design and drafting of the tariff for the CAISO’s Extended Day-Ahead Market, which was approved by FERC in December 2023. In addition, APS is participating in the Western Resource Adequacy Program administered by Western Power Pool. These efforts are driven by three objectives of reducing customer cost, improving reliability, and incorporating more clean energy on APS’s system. In terms of generation affordability, every three years, APS performs a comprehensive study, called an Integrated Resource Plan, to identify how much energy our customers will need over the next 15 years and what resources will be used to meet those needs. In developing the IRP, APS considers factors that include how much economic growth is expected, what new technologies might be available and how weather can impact the demand for energy. These inputs are then used to develop a plan that prioritizes reliability, affordability, and a clean, balanced energy mix. In November 2023, APS released its latest IRP, which shows that energy demand is growing at an unprecedented rate. This is due to continued residential and commercial customer growth throughout Arizona. To keep pace with the fast-growing demand for electricity and maintain reliability, APS needs to add new electricity generating resources. To ensure that the most affordable and reliable solutions are selected, APS issued All-Source Request for Proposals (“RFPs”) in 2022 and 2023. These RFPs are open to all technologies, including customer-scale (behind the meter) and utility-scale (front of the meter) resources. Through this process, APS has consistently found that clean resources like wind and solar, when coupled with energy storage technology, are among the most affordable options available today. Over the long term, these resources are expected to provide the greatest value as part of a diverse energy mix. In addition to managing the cost of electricity generation, APS has continued building upon existing cost management efforts, including a customer affordability initiative launched in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and achieving internal efficiencies. APS continues to drive this initiative by identifying opportunities to streamline its business processes, mitigate cost increases, increase employee retention, and improve customer satisfaction. 60 Table of Contents Clean Energy Commitment We are committed to doing our part to build a clean and carbon-free future. As Arizona stewards, we do what is right for the people and prosperity of Arizona. Our vision is to create a sustainable energy future for Arizona by providing reliable, affordable, and clean energy to our customers. We can accomplish our vision by collaborating with customers, communities, employees, policymakers, shareholders, and other stakeholders. Our clean energy commitment is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers. APS’s clean energy commitment consists of three parts: •A 2050 goal to provide 100% clean, carbon-free electricity; •A 2030 target to achieve a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and •A commitment to exit from coal-fired generation by 2031. APS’s ability to successfully execute its clean energy commitment depends upon a number of important external factors, including a supportive regulatory environment, sales and customer growth, development of clean energy technologies, and continued access to capital markets among others. 2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. Achieving this 2050 goal will require, among other things, innovative thinking, emergent clean energy and storage technologies, upgrades and expansions to the grid, and supportive public policy. 2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean and plans to continue to add more renewables and energy storage. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy. “Clean” is measured as percent of energy mix, which includes all carbon-free resources like nuclear, renewables, and demand-side management. “Renewable” energy includes generation resources such as solar, wind, and biomass, and is measured in accordance with the 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 annual carbon emissions that were 24% lower in 2022 compared to 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units during 2025. In June 2021, APS and the owners of Four Corners entered into an agreement that would allow Four Corners to operate seasonally at the election of the owners as early as fall 2023, subject to the necessary governmental approvals and conditions associated with changes in plant ownership. Under seasonal operation, one generating unit would be shut down during seasons where electricity demand is reduced, such as the winter and spring. The other unit would remain online year-round, subject to market 61 Table of Contents conditions as well as planned maintenance outages and unplanned outages. As of the date of this report, APS has elected not to begin seasonal operation due to market conditions. Renewables. APS’s IRP (see Note 3 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, one of the nation’s largest carbon-free, clean energy resource, which provides the foundation for reliable and affordable service for APS customers. APS’s longer-term clean energy strategy includes pursuing the right mix of purchased power contracts for new facilities, procurement of new facilities to be owned by APS, and the ongoing development of distributed energy resources. 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. On June 30, 2023, APS issued an RFP (the “2023 RFP”) seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources with a focus on in-service dates between 2026 and 2028. Bids from the 2023 RFP were received on September 6, 2023, and APS has started negotiations on multiple projects, including a 400 MW wind facility PPA that was signed in December 2023. 62 Table of Contents The following table summarizes the resources in APS’s renewable energy portfolio that are in operation or under development as of December 31, 2023. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting, and interconnection of the projects to the electric grid. [[GREPCENT_TABLE]] [["","Net Capacity in Operation (MW)","","Net Capacity Planned / Under Development (MW)"],["Total APS Owned: Solar","415","","\u2014"],["PPAs Renewables:"],["Solar","370","","1,261"],["Wind","637","","616"],["Geothermal","10","","\u2014"],["Biomass","14","","\u2014"],["Biogas","3","","\u2014"],["Total PPAs","1,034","","","1,877"],["Total Distributed Energy: Solar (a)","1,623","","","61","","(b)"],["Total Renewable Portfolio","3,072","","","1,938"]] [[/GREPCENT_TABLE]] (a)    Includes rooftop solar facilities owned by third parties. Distributed generation is produced in Direct Current and is converted to Alternating Current for reporting purposes. (b)    Applications received by APS that are not yet installed and online. Energy Storage. APS deploys a number of advanced technologies on its system, including energy storage. Energy storage provides capacity, improves power quality, can be utilized for system regulation and, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage also aids in integrating renewable generation by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to meet customer reliability requirements, increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. As noted above, on June 30, 2023, APS issued the 2023 RFP seeking approximately 1,000 MW of reliable capacity, including at least 700 MW of renewable resources, including energy storage, with a focus on in-service dates between 2026 and 2028. APS currently plans to install more than 2,700 MW of utility scale energy storage by 2026, including through energy storage projects under PPAs and AZ Sun retrofits as well as through resources solicited through current and future RFPs. 63 Table of Contents The following table summarizes the resources in APS’s energy storage portfolio that are in operation and under development as of December 31, 2023. Agreements for the development and completion of future resources are subject to various conditions. [[GREPCENT_TABLE]] [["","Net Capacity in Operation (MW)","","Net Capacity Planned / Under Development (MW)"],["APS Owned Energy Storage","182","(a)","19","(b)"],["PPAs Energy Storage","60","","2,182"],["Customer-Sited Energy Storage","30","","20"],["Total Energy Storage Portfolio","272","","2,221"]] [[/GREPCENT_TABLE]] (a)    Includes 0.3 MW of APS-owned customer-sited batteries. (b)    Includes 19 MW of capacity that entered commercial operation in January 2024. Palo Verde. Palo Verde, one of the nation’s largest carbon-free, clean energy resources, will continue to be a foundational part of APS’s resource portfolio. Palo Verde is not just the cornerstone of our current clean energy mix; it also is a significant provider of clean energy to the southwestern United States. The plant is a critical asset to the Southwest, generating more than 32 million MWh annually – enough power for roughly 3.4 million households, or approximately 8.5 million people. Its continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy. Developing Clean Energy Technologies Electric Vehicles As a part of the statewide transportation electrification plan (“TE Plan”) approved by the ACC in 2021, APS has a goal of supporting 450,000 light-duty electric vehicles (“EV”) in its service territory by 2030. In furtherance of this goal, through its Take Charge AZ Pilot Program, and as of December 31, 2023, APS installed 758 Level 2 charging ports at 183 customer locations and DC fast charging stations that are owned and operated by APS at five locations in Arizona. In December 2023, the ACC voted to discontinue the Take Charge AZ Pilot Program (“TCAZ”) while allowing APS to complete projects that were already underway. Additionally, as part of APS’s DSM Plan, APS launched an Electric Vehicle Charging Demand Management Pilot Program to proactively address the growing electric demand from charging as EVs become more widely adopted. The EV related programs in the DSM Plan also include the APS SmartCharge data gathering program, Fleet Advisory Services, and a $100 rebate to home builders for new homes to be built EV-ready with 240V charging station garage outlets. APS filed its 2024 DSM Plan on November 30, 2023. The 2024 DSM Plan includes APS’s 2024 TE Plan and, among other things, proposes two new programs: an expanded residential EV Charging Demand Management Program, and a Commercial EV Make-Ready Program. The ACC has yet to decide on the 2024 DSM Plan. Hydrogen Production On May 12, 2022, Arizona’s three public universities, along with four Arizona energy providers, including APS, announced the formation of a new, interdisciplinary coalition, called the Arizona Center for a Carbon Neutral Economy (“AzCaNE”), with the goal of achieving a carbon neutral economy in Arizona. AzCaNE’s first action was to pursue an Arizona-led approach to securing regional clean hydrogen hub 64 Table of Contents 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 efforts. AzCaNE submitted an initial hydrogen hub concept paper to the DOE, which in turn encouraged the submission of a full application for funding. In response, AzCaNE formed the Southwest Clean Hydrogen Innovation Network (“SHINe”) and submitted an application for funding its behalf. SHINe was not, however, selected as one of the seven regional hubs to be awarded funding by DOE. APS is currently maintaining a participatory role in AzCaNE as the organization continues to explore ways to educate stakeholders and promote low-carbon technologies. Carbon Capture Carbon Capture Utilization and Storage (“CCUS”) technologies can isolate CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. CCUS technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. APS will continue to monitor this emerging technology, particularly in regard to EPA’s proposed Greenhouse Gas (GHG) rule. On May 23, 2023, the EPA proposed regulations for GHG emissions that would, among other things, require CCUS technologies for certain classifications of coal-, oil-, and natural gas-fired electricity generating units dependent upon a variety of factors including retirement date and operating capacity. See Note 10 for more information. Sustainability Practices In 2020, in support of our clean energy commitment and the growing focus on sustainability within our organization, we increased our focus on sustainability by dedicating a new Sustainability Department at Pinnacle West responsible for integrating responsible business practices into the everyday work of the Company. The Sustainability Department engaged the Electric Power Research Institute (“EPRI”) and leveraged input from employees, large customers, limited-income advocates, economic development groups, environmental non-governmental organizations, leading sustainability academics and other stakeholders to identify and assess the sustainability issues that matter most. In total, 23 Priority Sustainability Issues (“PSIs”) were identified and prioritized. The most critical category includes four issues deemed most important and most able to be impacted by our actions: clean energy, customer experience, energy access and reliability, and safety and health. These PSIs provide the foundation for informing our strategic direction, creating a framework for incorporating best practices and driving enterprise-wide alignment and accountability. The Company also benchmarked best practices within the top four PSIs and has utilized this information to identify opportunities for improvement. Finally, the Company maintains an annual Corporate Responsibility Report on the Pinnacle West website (www.pinnaclewest.com/corporate-responsibility). The report provides information related to the Company’s sustainability practices and performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into or otherwise a part of this report. 65 Table of Contents Artificial Intelligence To address the emergence of artificial intelligence technology risk and opportunities, APS has developed a cross functional governance structure with leadership and experts from our information technology, cybersecurity, human resources, ethics, supply chain, legal, and nuclear generation teams. This cross functional structure will assess both the opportunities and risks during the technology intake process to ensure compliance with data security and reliability requirements, while observing market trends in this rapidly evolving area. Regulatory Overview 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 were: •a test year comprised of twelve months ended June 30, 2022, adjusted as described below; •an original cost rate base of $10.5 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits; •the following proposed capital structure and costs of capital: [[GREPCENT_TABLE]] [["","","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","%"]] [[/GREPCENT_TABLE]] •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 66 Table of Contents •twelve months of post-Test Year plant investments to reflect used and useful projects that will be placed into service prior to July 1, 2023. On June 5, 2023 and June 15, 2023, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommends among other things, (i) a $251 million revenue increase or, as an alternative, a $312 million revenue increase, (ii) a 9.6% return on equity, (iii) a 0.0% fair value increment or, as an alternative, a 0.75% fair value increment, and (iv) a continuation of a 12-month post-test year plant. RUCO recommends, among other things, (i) an $84.9 million revenue increase, (ii) an 8.2% return on equity or, as an alternative, an 8.7% return on equity if the ACC imputes a hypothetical capital structure with a 46% equity layer, (iii) a fair value increment of 0.0%, and (iv) a reduction of post-test year plant to six months. On July 12, 2023, APS filed rebuttal testimony addressing the ACC Staff and intervenors’ direct testimonies. The principal provisions of APS’s rebuttal testimony were: •reducing the revenue requirement increase to $383.1 million, which reduced the average annual customer bill impact to an increase of 11.3%; •maintaining a return on equity request of 10.25%; •reducing the increment of fair value rate base return to 0.5% from 1.0%; •maintaining a post-test year plant request of 12 months, plus the Four Corners Effluent Limitation Guidelines (“ELG”) project; •withdrawing the Payment Fee Removal Proposal (net reduction) which was originally requested in APS’s initial application; •maintaining the LFCR and DSMAC as separate adjustors; •increasing the PSA annual rate change limit from $0.004/kWh to $0.006/kWh; •proposing a new System Reliability Benefit (“SRB”) recovery mechanism; •maintaining the REAC in its current state; •maintaining adjustor base transfers and elimination of EIS; and •maintaining the request to recover CCT funding. On July 26, 2023, the ACC Staff, RUCO and other intervenors filed their surrebuttal testimony with the ACC. The ACC Staff adjusted their initial recommendations to, among other things, (i) a $281.9 million revenue increase, (ii) a 9.68% return on equity, (iii) a 0.5% fair value increment, (iv) a continuation of a 12-month post-test year plant that includes the Four Corners ELG project, and (v) support of an increase to the annual PSA increase limit to $0.006/kWh. RUCO maintained their direct position and also recommended further review of the PSA in a second phase of the 2022 Rate Case. On August 4, 2023, APS filed rejoinder testimony addressing the ACC Staff and intervenors’ surrebuttal testimonies. APS’s rejoinder testimony included final post-Test Year Plant values, reducing the revenue requirement increase to $377.7 million from $383.1 million, which reduced the average annual customer bill impact to an increase of 11.2%. All other major provisions from APS’s rebuttal testimony were maintained in its rejoinder testimony. On November 6, 2023, and November 21, 2023, APS and stakeholders filed briefs in the 2022 Rate Case. APS’s briefs included the reduction of the total revenue requirement increase to $376.2 million and a resulting average annual customer bill impact increase of 11.1%. All other major provisions from APS’s rejoinder testimony were maintained in its briefs. ACC Staff’s briefs included a proposed total revenue 67 Table of Contents requirement increase from $281.9 million to $282.7 million and also included their support of APS’s SRB mechanism, contingent on increased stakeholder outreach. On January 25, 2024, an Administrative Law Judge issued a Recommended Opinion and Order in the 2022 Rate Case, as corrected on February 6, 2024 (the “2022 Rate Case ROO”). The 2022 Rate Case ROO recommended, among other things, (i) a $523.1 million increase in the annual base rate revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.36%, (v) 12 months of post-test year plant and the inclusion of the Four Corners ELG project, (vi) the approval of APS’s SRB proposal with certain procedural and other modifications, (vii) no additional CCT funding, (viii) a 5.0% return on the prepaid pension asset and a return of 5.35% on the OPEB liability, and (ix) no disallowances on APS’s coal contracts. The 2022 Rate Case ROO also recommended a number of changes to existing adjustors, including (i) the approval of modified DSM performance incentives and the requested DSM transfer to base rates, (ii) the retention of $1.9 million of REAC in the adjustor rather than base rates, (iii) a partial transfer of $27.1 million of LFCR funds to base rates, and (iv) the adoption of an increase in the annual PSA cap to $0.006/kWh. On February 22, 2024, the ACC approved a number of amendments to the 2022 Rate Case ROO that resulted in, among other things, (i) an approximately $491.7 million increase in the annual base revenue requirement, (ii) a 9.55% return on equity, (iii) a 0.25% return on the increment of fair value rate base greater than original cost, (iv) an effective fair value rate of return of 4.39%, (v) a return set at the Company’s weighted average cost of capital on the net prepaid pension asset and net other post-employment benefit liability in rate base, (vi) an adjustment to generation maintenance and outage expense to reflect a more reasonable level of test year costs, (vii) approval of the SRB mechanism with modifications to customer notifications, procedural timelines and the inclusion of any qualifying technology and fuel source bid received through an all-source RFP, and (viii) recovery of all DSM costs through the DSMAC rather than through base rates. The ACC’s decision results in an expected total net annual revenue increase for APS of approximately $253.4 million and a roughly 8% increase to the typical residential customer’s bill. The ACC is expected to issue the final order for the 2022 Rate Case in March 2024 with the new rates to become effective for all service rendered on and after March 8, 2024. 2019 Retail Rate Case On October 31, 2019, APS filed an application with the ACC (the “2019 Rate Case”) for an annual increase in retail base rates. On August 2, 2021, an Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. Subsequently, the ACC approved an amended 2019 Rate Case ROO on November 2, 2021 (the “2019 Rate Case Decision”). See Note 3 for information regarding the 2019 Rate Case ROO. After the 2019 Rate Case Decision, APS filed an application for rehearing of the 2019 Rate Case and later filed a Notice of Direct Appeal by APS at the Arizona Court of Appeals, requesting review of certain matters from the 2019 Rate Case Decision. The Arizona Court of Appeals affirmed in part and reversed in part the ACC’s decision in the 2019 Rate Case, remanding the issue to the ACC for further proceedings. On June 14, 2023, APS and the ACC Legal Division filed a joint resolution with the ACC to 68 Table of Contents allow recovery of $215.5 million in costs related to the installation of the Four Corners SCR project, a reversal of the 20-basis point reduction to APS’s return on equity from 8.9% to 8.7% as a result of the 2019 Rate Case Decision, and recovery of $59.6 million in revenue lost by APS between December of 2021 and June 20, 2023. The joint resolution provides for a new Court Resolution Surcharge (“CRS”) mechanism, which is designed to recover the $59.6 million in revenue lost by APS between December 2021 and June 20, 2023, and the prospective recovery of ongoing costs related to the SCR investments and expense and the allowable return on equity difference in current base rates. On June 21, 2023, the ACC approved the joint resolution and proposals therein for recovery through the CRS mechanism, which became effective on July 1, 2023. The current CRS will be recalculated at the end of the 2022 Rate Case to remove the effects of the prospective recovery related to the allowable return on equity difference. On February 22, 2024, the ACC approved the 2022 Rate Case. The CRS tariff is currently being recalculated to reflect the final decision in that case. See Note 3 for more information regarding the 2019 Rate Case and Four Corners SCR cost recovery. The portion of the CRS representing the recovery of the $59.6 million of lost revenue between December of 2021 and June 20, 2023, $9.4 million of which has been collected as of December 31, 2023, will cease upon full collection of the lost revenue. Finally, recovery of ongoing costs related to the SCR investments will continue until the Company’s next rate case in which they can be incorporated therein. Regulatory Lag Docket On January 5, 2023, the ACC opened a new docket to explore the possibility of modifications to the ACC’s historical test year rules. The ACC requested comments from utilities and interested parties on ways to reduce regulatory lag, including alternative ratemaking structures such as future test years and hybrid test years. APS filed comments on June 1, 2023. APS cannot predict the outcome of this matter. See Note 3 for information regarding additional regulatory matters. 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 PNW Power and BCE. On August 4, 2023, Pinnacle West entered into a purchase and sale agreement pursuant to which we agreed to sell all of our equity interest in our wholly-owned subsidiary BCE to Ameresco (the “BCE Sale”). The transaction was accounted for as the sale of a business and closed in multiple stages. Certain investments and assets that BCE previously held, including the TransCanyon joint venture and holdings in the two Tenaska wind farm investments, were not included in the BCE Sale and were instead transferred to Pinnacle West Power, LLC (“PNW Power”), a newly-formed, wholly-owned subsidiary of Pinnacle West. The BCE Sale transaction was accounted for as the sale of a business and closed in multiple stages. As of December 31, 2023, all of BCE assets were classified as held for sale. The final closing of the BCE Sale was on January 12, 2024. See Note 20 for additional details. 69 Table of Contents PNW Power’s investments include TransCanyon, a 50/50 joint venture that was formed in 2014 with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. TransCanyon is pursuing independent electric transmission opportunities within the 11 U.S. states that comprise the Western Interconnection, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates. PNW Power’s investments also include minority ownership positions in two wind farms operated by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek and the 250 MW Nobles 2 wind farms. Clear Creek achieved commercial operation in May 2020; however, in the fourth quarter of 2022, PNW Power’s equity method investment was fully impaired. Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under long-term PPAs. PNW Power indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2. El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures.  In particular, El Dorado has committed to the following: •$25 million investment in the Energy Impact Partners fund, of which $16.7 million has been funded as of December 31, 2023. Energy Impact Partners is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. •$25 million investment in AZ-VC (formerly invisionAZ Fund), of which $6.3 million has been funded as of December 31, 2023. AZ-VC is a fund focused on analyzing, investing, managing, and otherwise dealing with investments in privately-held early stage and emerging growth technology companies and businesses primarily based in Arizona, or based in other jurisdictions and having existing or potential strategic or economic ties to companies or other interests in Arizona. The remainder of these investment commitments will be contributed by El Dorado as each investment fund selects and makes investments. Key Financial Drivers In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately. Electric Operating Revenues. For the years 2021 through 2023, retail electric revenues comprised approximately 91% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand, and prices. 70 Table of Contents Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.0% for the year ended December 31, 2023, compared with the prior-year period. For the three years through 2023, APS’s customer growth averaged 2.1% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2024 and the average annual growth to be in the range of 1.5% to 2.5% through 2026 based on anticipated steady population growth in Arizona during that period. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.5% for the year ended December 31, 2023, compared with the prior-year period. While steady customer growth was somewhat offset by weaker usage among residential customers, energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong sales to commercial and industrial customers and the ramp-up of new data center customers. For the three years through 2023, annual retail electricity sales growth averaged 2.7%, adjusted to exclude the effects of weather variations. Due to the expected growth of several large data centers and new large manufacturing facilities, we currently project that annual retail electricity sales in kWh will increase in the range of 2.0% to 4.0% for 2024 and that average annual growth will be in the range of 4.0% to 6.0% through 2026, including the effects of customer conservation, energy efficiency, and distributed renewable generation initiatives, but excluding the effects of weather variations. These projected sales growth ranges include the impacts of several large data centers and new large manufacturing facilities, which are expected to contribute to 2024 growth in the range of 2.5% to 3.5% and to average annual growth in the range of 3.0% to 5.0% through 2026. Longer term, APS has been preparing for and can serve significant load growth from residential and business customers. On top of these existing growth trends, APS is also now receiving unprecedented incremental requests for service from extra-large commercial energy users (over 25 MW) with very high energy demands that persist virtually around-the-clock. These incremental requests for service by extra-large energy users far exceed available generation and transmission resource capacity in the Southwest region for the foreseeable future. In April 2023, APS notified prospective extra-large customers without existing commitments from APS that it is not able to commit at this time to future extra-large projects of over 25 MW. Because of the high growth in demand for such projects, APS has developed a prioritization queue that identifies and prioritizes projects while maintaining system reliability and affordability for existing APS customers. APS is exploring available options for securing sufficient electric generation and transmission to meet these projections of future customer needs. Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, slower ramp-up of and/or fewer data centers and large manufacturing facilities, slower than expected commercial and industrial expansions, impacts of energy efficiency programs and growth in DG, responses to retail price changes, changes in regulatory standards, and impacts of new and existing laws and regulations, including environmental laws and regulations. Based on past experience, a 1% variation in our annual residential and small commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million, and a 1% variation in our annual large commercial and industrial kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $5 million. Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Our experience indicates that typical variations from normal 71 Table of Contents 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 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 10.0% of the assessed value for 2023, 10.2% for 2022, and 10.7% for 2021. Property taxes increased in 2023 due to higher plant balances related to expansion and improvements on our existing generation, transmission, and distribution facilities, partially offset by legislative changes reducing both property tax assessment ratios and rates in Arizona. Income Taxes.  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. Interest Expense.  Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. See Note 6 for further details. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed into service. 72 Table of Contents RESULTS OF OPERATIONS Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost-based rate regulation) and related activities and includes electricity generation, transmission, and distribution. All other segment activities are insignificant. Our regulated electricity segment activities are conducted primarily through our wholly-owned subsidiary, APS. Operating Results – 2023 compared with 2022 Our consolidated net income attributable to common shareholders for the year ended December 31, 2023, was $502 million, compared with $484 million for the prior year.  The results reflect an increase of approximately $18 million, primarily as a result of the effects of weather, higher CRS and LFCR revenue, higher transmission revenue, increased sales and usage, and higher other income. These positive factors were partially offset by higher interest charges, net of AFUDC, higher operations and maintenance expense, lower pension and other postretirement non-service credits, and higher depreciation and amortization expense mostly due to increased plant assets. The following table presents net income attributable to common shareholders compared with the prior year for Pinnacle West consolidated and for APS consolidated: [[GREPCENT_TABLE]] [["","APS Consolidated","","Pinnacle West Consolidated"],["","Year Ended December 31,","","Year Ended December 31,"],["","2023","","2022","","Net Change","","2023","","2022","","Net Change"],["","(dollars in millions)"],["Operating revenues","$","4,696","","","$","4,324","","","$","372","","","$","4,696","","","$","4,324","","","$","372"],["Fuel and purchased power expense","(1,793)","","","(1,629)","","","(164)","","","(1,793)","","","(1,629)","","","(164)"],["Operating revenues less fuel and purchased power expenses","2,903","","","2,695","","","208","","","2,903","","","2,695","","","208"],["Operations and maintenance","(1,044)","","","(974)","","","(70)","","","(1,059)","","","(987)","","","(72)"],["Depreciation and amortization","(794)","","","(753)","","","(41)","","","(794)","","","(753)","","","(41)"],["Taxes other than income taxes","(224)","","","(220)","","","(4)","","","(224)","","","(220)","","","(4)"],["Pension and other postretirement non-service credits, net","42","","","99","","","(57)","","","41","","","98","","","(57)"],["Other income and expenses, net","60","","","22","","","38","","","60","","","(1)","","","61"],["Interest charges, net of allowance for borrowed funds used during construction","(285)","","","(236)","","","(49)","","","(331)","","","(256)","","","(75)"],["Income taxes","(94)","","","(91)","","","(3)","","","(77)","","","(75)","","","(2)"],["Less income related to noncontrolling interests","(17)","","","(17)","","","\u2014","","","(17)","","","(17)","","","\u2014"],["Net Income Attributable to Common Shareholders","$","547","","","$","525","","","$","22","","","$","502","","","$","484","","","$","18"]] [[/GREPCENT_TABLE]] 73 Table of Contents Operating revenues less fuel and purchased power expenses.  Operating revenues less fuel and purchased power expenses were $208 million higher for the year ended December 31, 2023, compared with the prior year.  The following table summarizes the major components of this change: [[GREPCENT_TABLE]] [["","Increase (Decrease)"],["","Operating revenues","","Fuel and purchased power expenses","","Net change"],["","(dollars in millions)"],["LFCR revenue (Note 3)","$","55","","","$","\u2014","","","$","55"],["Effects of weather","46","","","12","","","34"],["CRS revenue (Note 3)","34","","","\u2014","","","34"],["Higher transmission revenues (Note 3)","26","","","\u2014","","","26"],["Higher retail revenue due to customer growth and changes in customer usage patterns and related pricing, partially offset by the impacts of energy efficiency and distributed generation","39","","","14","","","25"],["Higher renewable energy regulatory surcharges, partially offset by operations and maintenance costs","15","","","(8)","","","23"],["Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals","158","","","145","","","13"],["Miscellaneous items, net","(1)","","","1","","","(2)"],["Total","$","372","","","$","164","","","$","208"]] [[/GREPCENT_TABLE]] Operations and maintenance.  Operations and maintenance expenses increased $72 million for the year ended December 31, 2023, compared with the prior-year period primarily due to: •An increase of $31 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; •An increase of $22 million related to non-nuclear generation costs primarily due to higher operating costs and higher planned outages; •An increase of $14 million related to transmission, distribution, and customer service; •An increase of $13 million related to nuclear generation costs; •An increase of $10 million related to information technology costs; •A decrease of $26 million related to employee benefits, largely due to decreased pension and other post-retirement service costs of $12 million and other miscellaneous factors. See “pension and other postretirement non-service credits, net” below for additional discussion; and •An increase of $8 million for corporate resources and other miscellaneous factors. Depreciation and amortization.  Depreciation and amortization expenses were $41 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to increased plant in service. 74 Table of Contents Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $57 million lower for the year ended December 31, 2023, compared to the prior-year period primarily due to the effect of higher discount rates and actual market returns being lower than estimated returns in 2022. Other income and expenses, net. All other income and expenses, net were $61 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to higher interest income, higher allowance for equity funds used during construction due to increased capital expenditures, Clear Creak wind farm impairment (see Note 10) recorded in the prior year period, and the gain on the BCE Sale. See Note 20. The difference between APS’s and Pinnacle West’s other income and expenses, net primarily relates to BCE matters. Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $75 million higher for the year ended December 31, 2023, compared to the prior-year period primarily due to higher debt balances, higher commercial paper balances and higher interest rates in the current period, partially offset by higher allowance for borrowed funds due to increased capital expenditures. The difference between APS’s and Pinnacle West’s interest charges, net of allowance for borrowed funds used during construction is primarily relates to Pinnacle West’s higher term loan interest and BCE debt activity. Income taxes.  Income taxes were $2 million higher for the year ended December 31, 2023, compared with the prior-year period primarily due to higher pre-tax income, partially offset by Investment Tax Credit amortization from our Arizona Sun battery facilities, and Production Tax Credits from our Agave Solar facility, both of which went into service in 2023. LIQUIDITY AND CAPITAL RESOURCES 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 December 31, 2023, APS’s common equity ratio, as defined, was 49%.  Its total shareholder equity was approximately $7.2 billion, and total capitalization was approximately $14.7 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $5.9 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 75 Table of Contents commercial paper and its revolving credit facility. APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt.  APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West. APS is currently authorized to receive up to $150 million annually in equity infusions from Pinnacle West without seeking ACC approval. On October 27, 2023, APS sought approval from the ACC to receive from Pinnacle West in 2024 up to an additional $500 million in equity infusions above the authorized limit of $150 million, and on January 9, 2024, the ACC approved the increased equity infusion limit for 2024. Pinnacle West and APS maintain committed revolving credit facilities that enhance liquidity and provide credit support for accessing commercial paper markets. These credit facilities mature in 2028. See Note 5. Summary of Cash Flows The following tables present net cash provided by (used for) operating, investing, and financing activities for the years ended December 31, 2023, and 2022 (dollars in millions): Pinnacle West Consolidated [[GREPCENT_TABLE]] [["","2023","","2022"],["Net cash flow provided by operating activities","$","1,207","","","$","1,242"],["Net cash flow used for investing activities","(1,694)","","","(1,618)"],["Net cash flow provided by financing activities","487","","","371"],["Net decrease in cash and cash equivalents","$","\u2014","","","$","(5)"]] [[/GREPCENT_TABLE]] Arizona Public Service Company [[GREPCENT_TABLE]] [["","2023","","2022"],["Net cash flow provided by operating activities","$","1,275","","","$","1,230"],["Net cash flow used for investing activities","(1,687)","","","(1,549)"],["Net cash flow provided by financing activities","412","","","314"],["Net decrease in cash and cash equivalents","$","\u2014","","","$","(5)"]] [[/GREPCENT_TABLE]]  Operating Cash Flows 2023 Compared with 2022. Pinnacle West’s consolidated net cash provided by operating activities was $1,207 million in 2023 compared to $1,242 million in 2022, a decrease of $35 million in net cash provided primarily due to $204 million higher fuel and purchased power costs, $82 million higher payments for operations and maintenance costs, $66 million higher interest payments, $57 million lower customer advances for construction and $13 million change in net collateral, partially offset by $349 million higher cash receipts from electric revenues and $37 million lower income taxes. The difference between APS’s and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s lower income tax cash payments to Pinnacle West and other changes in working capital. Retirement plans and other postretirement benefits. 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 76 Table of Contents 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 estimated to be 110% funded as of January 1, 2024, and was 112% as of January 1, 2023. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  In 2022 and 2023, we did not make any contributions to our pension plan. In 2021, we made contributions to our pension plan totaling $100 million.  The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2024, 2025 or 2026. Regarding contributions to our other postretirement benefit plan, we did not make any contributions in 2023 or 2022 and do not expect to make any contributions in 2024, 2025 or 2026. The Company was reimbursed $23 million in 2023, $26 million in 2022, and $24 million in 2021 for prior years retiree medical claims from the other postretirement benefit plan trust assets. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, was 102% funded as of December 31, 2023, and our postretirement benefit plans were 162% funded, as measured for GAAP purposes at December 31, 2023. See Note 7 for additional details. The CARES Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020, through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020, through December 31, 2020, that was approximately $18 million. As of December 31, 2022, we have paid this cash deferral in full. Investing Cash Flows 2023 Compared with 2022. Pinnacle West’s consolidated net cash used for investing activities was $1,694 million in 2023 compared to $1,618 million in 2022, an increase of $76 million primarily related to increased capital expenditures and higher allowance for borrowed funds, partially offset by proceeds from the BCE Sale. See Note 20. The difference between APS’s and Pinnacle West’s net cash used for investing activities primarily relates to the BCE Sale. 77 Table of Contents Capital Expenditures.  The following table summarizes the estimated capital expenditures for the next three years: Capital Expenditures (dollars in millions) [[GREPCENT_TABLE]] [["","Estimated for the Year Ended December 31,"],["","2024","","2025","","2026"],["APS"],["Generation:"],["Clean:"],["Nuclear Generation","$","130","","","$","130","","","$","140"],["Renewables and Energy Storage Systems (\u201cESS\u201d) (a)","175","","","305","","","280"],["Other Generation (b)","455","","","320","","","235"],["Distribution","565","","","550","","","590"],["Transmission","340","","","415","","","420"],["Other (c)","285","","","280","","","385"],["Total APS","$","1,950","","","$","2,000","","","$","2,050"]] [[/GREPCENT_TABLE]] (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 PNW Power projects. Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include additions and improvements to existing fossil plants, such as our current modernization project at our Sundance gas plant. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers, and environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures. Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock. 78 Table of Contents Financing Cash Flows and Liquidity 2023 Compared with 2022. Pinnacle West’s consolidated net cash provided by financing activities was $487 million in 2023 compared to $371 million in 2022, an increase of $116 million in net cash provided primarily due to a net increase in short-term borrowings of $193 million and $117 million lower long-term debt repayments, partially offset by $186 million in lower issuances of long-term debt and higher dividend payments of $8 million. APS’s consolidated net cash provided by financing activities was $412 million in 2023 compared to $314 million in 2022, an increase of $98 million in net cash provided primarily due to a net increase in short-term borrowings of $135 million, partially offset by $29 million in lower issuances of long-term debt and higher dividend payments of $8 million. Significant Financing Activities.  On December 13, 2023, the Pinnacle West Board of Directors declared a dividend of $0.880 per share of common stock, payable on March 1, 2024, to shareholders of record on February 1, 2024. During 2023, Pinnacle West increased its indicated annual dividend from $3.46 per share to $3.52 per share. For the year ended December 31, 2023, Pinnacle West’s total dividends paid per share of common stock were $3.48 per share, which resulted in dividend payments of $386 million. 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. See Note 5 for more information on available credit facilities. Other Financing Matters.  See Note 15 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 December 31, 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. 79 Table of Contents On December 15, 2022, the ACC issued a financing order reaffirming the previous short-term debt authorization equal to the sum of (i) 7% of APS’s capitalization, and (ii) $500 million  (which is required to be used for costs relating to purchases of natural gas and power) and approving APS’s application filed April 6, 2022 requesting to increase the long-term debt limit from $7.5 billion to $8.0 billion and to exclude financing lease PPAs from the definition of long-term debt for purposes of the ACC financing orders. See Note 6 for further discussions of liquidity matters. Credit Ratings The ratings of securities of Pinnacle West and APS as of February 15, 2024, are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a potential downward revision to our credit ratings. [[GREPCENT_TABLE]] [["","Moody\u2019s","","Standard & Poor\u2019s","","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"]] [[/GREPCENT_TABLE]] 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 December 31, 2023. See Note 6. •Pinnacle West and APS maintain committed revolving credit facilities. See Note 5 for short-term debt details. 80 Table of Contents •Fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation. See Notes 3 and 10. Purchase obligations include capital expenditures and other obligations. See Note 10. 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 3 and 10. •APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 17. •APS must reimburse certain coal providers for final and contemporaneous coal mine reclamation. See Note 10. CRITICAL ACCOUNTING POLICIES AND ESTIMATES In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period.  Some of those judgments can be subjective and complex, and actual results could differ from those estimates.  We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved. Regulatory Accounting Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements.  Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates.  Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings.  Management judgments also include assessing the impact of potential ACC- or FERC-ordered refunds to customers on regulatory liabilities. We had $2,016 million of regulatory assets and $2,176 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2023. See Notes 1 and 3 for more information. Pensions and Other Postretirement Benefit Accounting Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position. We review these assumptions on an annual basis and adjust them as necessary. The most relevant actuarial 81 Table of Contents assumptions are the discount rate, the expected long-term rate of return on plan assets (“EROA”), and the assumed healthcare cost trend rates. Differences between these actuarial assumptions and actual plan results may create volatility in pension and other postretirement benefit expense. To reduce this volatility, these differences are accumulated and amortized (subject to a corridor of 10% of the greater of plan assets or obligations) as part of the expense over a period of approximately 11 years. Following are the most relevant actuarial assumptions: Discount Rate. The discount rate is used to measure the plan liability and net periodic cost. For this assumption, we utilize a yield curve produced by our actuary as of December 31st and employ their projections of the future benefit payments to estimate the projected benefit obligation for each plan. This process also yields a single equivalent discount rate that produces the same present value for the projection of estimated benefit payments that is generated by discounting each year’s benefit payments by a spot rate to that year. The spot rates are derived from a yield curve composed of domestic AA rated corporate bonds. EROA. The EROA is used to estimate earnings on invested funds over the long-term. For this assumption, we consider historical experience and future expectations of asset classes utilized in the portfolio. Healthcare Cost Trend Rates. We consider past performance and forecasts of health care costs and our actuary provides the Company with a medical trend recommendation based on national medical trend, historical claims performance, benchmarking, and plan design changes. The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2023, reported pension assets and liabilities on the Consolidated Balance Sheets and our 2023 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions): [[GREPCENT_TABLE]] [["","","Increase (Decrease)"],["Actuarial Assumption (a)","","Impact on Pension Plans","","Impact on Pension Expense"],["Discount rate (b):"],["Increase 1%","","$","(250)","","","$","(9)"],["Decrease 1%","","295","","","10"],["EROA:"],["Increase 1%","","\u2014","","","(19)"],["Decrease 1%","","\u2014","","","19"]] [[/GREPCENT_TABLE]] (a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point. (b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. Additionally, the Pension Plan utilizes a liability-driven strategy for its pension asset portfolio, and the obligation and expense sensitivities shown above do not reflect the offsetting impact that a change in interest rates may have on pension asset values. 82 Table of Contents The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2023, other postretirement benefit obligation on the Pinnacle West’s Consolidated Balance Sheets and our 2023 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):  [[GREPCENT_TABLE]] [["","","Increase (Decrease)"],["Actuarial Assumption (a)","","Impact on Other Postretirement Benefit Plans","","Impact on Other Postretirement Benefit Expense"],["Discount rate (b):"],["Increase 1%","","$","(42)","","","$","(2)"],["Decrease 1%","","51","","","2"],["Healthcare cost trend rate (c):"],["Increase 1%","","42","","","5"],["Decrease 1%","","(36)","","","(4)"],["EROA \u2013 pretax:"],["Increase 1%","","\u2014","","","(4)"],["Decrease 1%","","\u2014","","","4"]] [[/GREPCENT_TABLE]] (a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point. (b)In general, changes in the discount rate will not typically have symmetrical effects for increases and decreases of the rate. Further, a 1% change in a low discount rate environment will have a larger impact than a 1% change in a high discount rate environment. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated. (c)This assumes a 1% change in the initial and ultimate healthcare cost trend rate. See Note 7 for further details about our pension and other postretirement benefit plans. Fair Value Measurements We account for derivative instruments, investments held in our nuclear decommissioning trusts fund, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis.  Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  The significance of a particular input determines how the instrument is classified in a fair value hierarchy.  The determination of fair value sometimes requires subjective and complex judgment.  Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy.  Actual results could differ from our estimates of fair value.  See Note 1 for a discussion of accounting policies and Note 12 for fair value measurement disclosures. 83 Table of Contents Asset Retirement Obligations We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. AROs as of December 31, 2023 are described further in Note 11. OTHER ACCOUNTING MATTERS See Note 21 for two new accounting standards that were issued in November and December 2023, respectively, that are pending adoption: ASU 2023-07, Improvements to Reportable Segment Disclosures, effective for us for annual periods on December 31, 2024, and interim periods thereafter, and ASU 2023-09, Improvements to Income Tax Disclosures, effective for us for annual periods on December 31, 2025. MARKET AND CREDIT RISKS Market Risks Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trusts, other special use funds and benefit plan assets. Interest Rate and Equity Risk We have exposure to changing interest rates.  Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Notes 12 and 18), and benefit plan assets.  The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments.  Nuclear decommissioning, coal reclamation, and benefit plan costs are recovered in regulated electricity prices. 84 Table of Contents The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2023, and 2022.  If variable interest rates were to increase by 10% from the December 31, 2023, levels, it would not have a material effect on Pinnacle West Consolidated or APS Consolidated annual interest expense. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2023, and 2022 (dollars in millions): Pinnacle West – Consolidated [[GREPCENT_TABLE]] [["","","Short-Term Debt","","Variable-Rate Long-Term Debt","","Fixed-Rate Long-Term Debt"],["","","Interest","","","","Interest","","","","Interest"],["2023","","Rates","","Amount","","Rates","","Amount","","Rates","","Amount"],["2024","","5.46","%","","$","610","","","6.20","%","","$","625","","","3.35","%","","$","250"],["2025","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","1.99","%","","800"],["2026","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.55","%","","250"],["2027","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.95","%","","300"],["2028","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Years thereafter","","\u2014","","","\u2014","","","4.11","%","","164","","","4.22","%","","6,080"],["Total","","","","$","610","","","","","$","789","","","","","$","7,680"],["Fair value","","","","$","610","","","","","$","789","","","","","$","6,767"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","","Short-Term Debt","","Variable-Rate Long-Term Debt","","Fixed-Rate Long-Term Debt"],["","","Interest","","","","Interest","","","","Interest"],["2022","","Rates","","Amount","","Rates","","Amount","","Rates","","Amount"],["2023","","4.56","%","","$","341","","","5.42","%","","$","51","","","\u2014","","","$","\u2014"],["2024","","\u2014","","","\u2014","","","5.10","%","","450","","","3.35","%","","250"],["2025","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","1.99","%","","800"],["2026","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.55","%","","250"],["2027","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.95","%","","300"],["Years thereafter","","\u2014","","","\u2014","","","3.96","%","","163","","","4.10","%","","5,580"],["Total","","","","$","341","","","","","$","664","","","","","$","7,180"],["Fair value","","","","$","341","","","","","$","664","","","","","$","5,922"]] [[/GREPCENT_TABLE]] The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2023, and 2022.  The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2023, and 2022 (dollars in millions): 85 Table of Contents APS — Consolidated [[GREPCENT_TABLE]] [["","","Short-Term Debt","","Variable-Rate Long-Term Debt","","Fixed-Rate Long-Term Debt"],["","","Interest","","","","Interest","","","","Interest"],["2023","","Rates","","Amount","","Rates","","Amount","","Rates","","Amount"],["2024","","5.46","%","","$","533","","","\u2014","","","$","\u2014","","","3.35","%","","$","250"],["2025","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","3.15","%","","300"],["2026","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.55","%","","250"],["2027","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.95","%","","300"],["2028","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","\u2014"],["Years thereafter","","\u2014","","","\u2014","","","4.11","%","","164","","","4.22","%","","6,080"],["Total","","","","$","533","","","","","$","164","","","","","$","7,180"],["Fair value","","","","$","533","","","","","$","164","","","","","$","6,296"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","","Short-Term Debt","","Variable-Rate Long-Term Debt","","Fixed-Rate Long-Term Debt"],["","","Interest","","","","Interest","","","","Interest"],["2022","","Rates","","Amount","","Rates","","Amount","","Rates","","Amount"],["2023","","4.56","%","","$","325","","","\u2014","","","$","\u2014","","","\u2014","","","$","\u2014"],["2024","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","3.35","%","","250"],["2025","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","3.15","%","","300"],["2026","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.55","%","","250"],["2027","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","2.95","%","","300"],["Years thereafter","","\u2014","","","\u2014","","","3.96","%","","163","","","4.10","%","","5,580"],["Total","","","","$","325","","","","","$","163","","","","","$","6,680"],["Fair value","","","","$","325","","","","","$","163","","","","","$","5,466"]] [[/GREPCENT_TABLE]] Commodity Price Risk We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas.  Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies.  We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps.  As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas.  The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. The following table shows the net pretax changes in mark-to-market of our energy derivative positions (dollars in millions): [[GREPCENT_TABLE]] [["","December 31, 2023","","December 31, 2022"],["Mark-to-market of net positions at beginning of year","$","96","","","$","107"],["Decrease (increase) in regulatory asset","(216)","","","(11)"],["Mark-to-market of net positions at end of year","$","(120)","","","$","96"]] [[/GREPCENT_TABLE]] 86 Table of Contents The table below shows the fair value of maturities of our energy derivative contracts (dollars in millions) at December 31, 2023, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods. [[GREPCENT_TABLE]] [["Source of Fair Value","","","2024","","2025","","2026","","2027","","2028","","Total Fair Value"],["Observable prices provided by other external sources","","","$","(82)","","","$","(41)","","","$","(2)","","","$","\u2014","","","$","\u2014","","","$","(125)"],["Prices based on unobservable inputs","","","5","","","\u2014","","","\u2014","","","\u2014","","","\u2014","","","5"],["Total by maturity","","","$","(77)","","","$","(41)","","","$","(2)","","","$","\u2014","","","$","\u2014","","","$","(120)"]] [[/GREPCENT_TABLE]] The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets (dollars in millions): [[GREPCENT_TABLE]] [["","December 31, 2023Gain (Loss)","","December 31, 2022Gain (Loss)"],["","Price Up 10%","","Price Down 10%","","Price Up 10%","","Price Down 10%"],["Mark-to-market changes reported in:"],["Regulatory asset (liability) (a)"],["Electricity","$","9","","","$","(9)","","","$","12","","","$","(12)"],["Natural gas","55","","","(55)","","","55","","","(55)"],["Total","$","64","","","$","(64)","","","$","67","","","$","(67)"]] [[/GREPCENT_TABLE]] (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 15 for a discussion of our credit valuation adjustment policy.