POWERING GROWTH DELIVERING VALUE Second Quarter 2022 Results August 3, 2022 1

Forward Looking Statements 2 This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings guidance and financial outlook and goals. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project,” "anticipate," "goal," "seek," "strategy," "likely," "should," "will," "could," and similar words. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. These factors include, but are not limited to: the potential effects of the continued COVID-19 pandemic, including, but not limited to, demand for energy, economic growth, our employees and contractors, vaccine mandates, supply chain, expenses, inflation, capital markets, capital projects, operations and maintenance activities, uncollectable accounts, liquidity, cash flows, or other unpredictable events; our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels; variations in demand for electricity, including those due to weather, seasonality (including large increases in ambient temperatures), the general economy or social conditions, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements; the potential effects of climate change on our electric system, including as a result of weather extremes such as prolonged drought and high temperature variations in the area where APS conducts its business; power plant and transmission system performance and outages; competition in retail and wholesale power markets; regulatory and judicial decisions, developments and proceedings; new legislation, ballot initiatives and regulation or interpretations of existing legislation or regulations, including those relating to environmental requirements, regulatory and energy policy, nuclear plant operations and potential deregulation of retail electric markets; fuel and water supply availability; our ability to achieve timely and adequate rate recovery of our costs through our rates and adjustor recovery mechanisms, including returns on and of debt and equity capital investments; our ability to meet renewable energy and energy efficiency mandates and recover related costs; the ability of APS to achieve its clean energy goals (including a goal by 2050 of 100% clean, carbon-free electricity) and, if these goals are achieved, the impact of such achievement on APS, its customers, and its business, financial condition and results of operations; risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; current and future economic conditions in Arizona, including in real estate markets; the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, war, acts of war, international sanctions, terrorist attack, physical attack, severe storms, or other catastrophic events, such as fires, explosions, pandemic health events, or similar occurrences; the development of new technologies which may affect electric sales or delivery; the cost of debt and equity capital and the ability to access capital markets when required; general economic conditions, including inflation rates, monetary fluctuations and supply chain constraints; environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions; volatile fuel and purchased power costs; the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements; the liquidity of wholesale power markets and the use of derivative contracts in our business; potential shortfalls in insurance coverage; new accounting requirements or new interpretations of existing requirements; generation, transmission and distribution facility and system conditions and operating costs; the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region; the willingness or ability of our counterparties, power plant participants and power plant land-owners to meet contractual or other obligations or extend the rights for continued power plant operations; and restrictions on dividends or other provisions in our credit agreements and ACC orders. These and other factors are discussed in Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, and Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, which you should review carefully before placing any reliance on our financial statements, disclosures or earnings outlook. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law. In this presentation, references to net income and earnings per share (EPS) refer to amounts attributable to common shareholders. Second Quarter 2022

2nd Quarter results negatively impacted by rate case outcome 3 2nd Quarter 2022 vs. 2nd Quarter 2021 2Q 2021 2Q 2022 $1.91 $1.45 Operating Revenue less Fuel and Purchased Power1 $(0.14) O&M1 & 2 $(0.10) D&A2 $(0.18) Operating Revenue less Fuel and Purchased Power Federal Tax Reform3 Sales/Usage Weather Other Transmission LFCR GRC Base Rate Impact $ $ $ $ $ $ $ 0.25 0.03 (0.02) (0.02) (0.03) (0.11) (0.24) Pension & OPEB Non- service Credits, net $(0.02) All other, net2,4 $(0.06) 1 Includes costs and offsetting operating revenues associated with renewable energy and demand side management programs, see slide 20 for more information. 2 Includes the impacts from the absence of the Four Corners Selective Catalytic Reduction (SCR) equipment and Ocotillo Modernization Project (OMP) deferrals, and the elimination of State Equalization Tax Rate (SETR). 3 TEAM adjuster was transferred into Base Rates upon the conclusion of APS’s most recent rate case. 4 The Q2 2022 effective tax rate is impacted by a change in the timing of recognition for excess deferred taxes related to the 2017 Tax Cuts and Jobs Act. This timing difference is expected to resolve by year end. Second Quarter 2022 Other Taxes2 $0.04

Key drivers for EPS guidance1 1 • Retail customer growth 1.5%-2.5% • Weather-normalized retail electricity sales growth of 1.5%-2.5% • Transmission revenues • Operations and maintenance • Depreciation and amortization Second Quarter 20224 2022 key drivers • 2022 EPS guidance $3.90-$4.10 • Long-term EPS growth target of 5-7%2 • Retail customer growth 1.5%-2.5%3 • Weather-normalized retail electricity sales growth of 3.5-4.5%3 1 As of August 3, 2022. Long-term guidance and key drivers • Property Tax • Interest expense • AFUDC • Pension and OPEB 2 Long-term EPS growth rate based on the Company’s current 5-year compound annual growth rate projections from 2022-2026 3 Forecasted guidance range from 2022-2024

$170 $175 $185 $190 $595 $510 $530 $500 $263 $250 $210 $210 $260 $340 $330 $560 $214 $250 $270 $190 2021 2022E 2023E 2024E Other Generation Clean Generation Transmission Distribution Other Total 2022-2024 $4.7B $1.50B $1.53B $1.53B $1.65B 5 Managed capital plan to support customer growth, reliability, and clean transition 2022–2024 as disclosed in the Second Quarter 2022 Form 10-Q. Second Quarter 2022

Total Approved Rate BaseAPS Rate Base Growth Guidance Year-End Steady rate base growth Second Quarter 20226 ACC FERC Rate Effective Date 12/01/2021 6/1/2022 Test Year Ended 06/30/20191 12/31/2021 Rate Base $8.6B $1.9B Equity Layer 54.7% 51.3% Allowed ROE 8.7% 10.75% 1 Adjusted to include post test-year plant in service through 06/30/2020 Rate base $ in billions, rounded $9.1 $11.2 $1.8 $2.4 2020 2021 2022 2023 2024 Projected 5-6% Annual FERC ACC $10.9 $13.6

Our goal is flat total O&M and declining O&M per MWh 7 2021 2022 2023 2024 $29/MWh O&M per MWh Total O&M1 2021: $865M 2022: $820M-$840M 1 Total O&M amounts exclude RES/DSM, and include planned outage amounts of $54M in 2021 and $40M-$50M in 2022. Second Quarter 2022

Forecasted sources of capital to fund investments through 2024 No plans to issue equity before end of next rate case 8 Approx. $3 billion Approx. $1 billion $4.7 billion APS Debt2 PNW Debt2 Cash from Operations1 $200-$300 million $400-$500 million 1 Cash from operations is net of shareholder dividends. 2 APS and PNW debt issuance is net of maturities. Second Quarter 2022 Total Capital Investment PNW Equity/ Alternatives

Strong balance sheet with attractive long-term debt maturity profile1 9 $M PNW Long-Term DebtAPS Long-Term Debt $0 $200 $400 $600 $800 $1,000 $1,200 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050 As of June 30, 2022 Second Quarter 2022 1 Does not include debt at Bright Canyon Energy.

Pension & Other Post Retirement Benefits (“OPEB”) 10 Second Quarter 2022 97% 104% 107% YE 2019 YE 2020 YE 2021 Pension Funded Status1 • Liability driven investment strategy helps to minimize the impact of market volatility on funded status • Pension portfolio has an 80% target allocation to fixed income assets • Hedge 100% of interest rate volatility using a combination of fixed income portfolio assets and U.S. Treasury Futures contracts ($ in millions) 1 Excludes supplemental excess benefit retirement plan calculated on a PBO basis. . Benefit Expense Notes • Using the corridor accounting approach, gains and losses outside of the established corridor are amortized to benefit expense over the average service life • Gains and losses within the corridor do not impact benefit expense • Application of the corridor approach is a GAAP prescribed accounting method that is commonly utilized throughout the utility industry • Consistent with liability driven investing, at a higher funded status more historically-volatile assets are removed from the portfolio and replaced with fixed income securities, which is expected to reduce benefit cost volatility • Once fixed income assets in the portfolio are valued at year-end and any gains/losses are recognized, the future year expected return on fixed income assets changes with the then-prevailing level of fixed income yields Contributions 2021A 2022E 2023E 2024E Pension $100 $0 $0 $0 OPEB $0 $0 $0 $0

We continue to make progress towards key deliverables Second Quarter 202211 ➢ File appeal of last rate case ✓ Filed notice of appeal on December 17 ✓ Filed opening brief on April 27 ✓ Filed reply brief on July 27 ➢ Make progress on financing plan ✓ Deferring equity issuance until after next rate case ➢ File new rate case to recover grid investments and reduce regulatory lag ✓ Filed Notice of Intent in June ➢ Work with stakeholders on common issues ✓ Received approval of Customer Education and Outreach Plan ➢ Flat total O&M and declining O&M per MWh ➢ Continued progress towards Clean Energy Commitment ➢ Continued support in attracting high tech growth and economic development

APPENDIX

2022 EPS guidance Second Quarter 202213 Key Factors and Assumptions as of August 3, 2022 2022 Adjusted gross margin (operating revenues, net of fuel and purchased power expenses, x/RES,DSM,CCT) $2.52 – $2.55 billion • Retail customer growth about 1.5-2.5% • Weather-normalized retail electricity sales volume 1.5-2.5% higher compared to prior year o Includes 0.5-1.5% contribution to sales growth of new large manufacturing facilities and several large data centers • Assumes normal weather for full-year forecast Adjusted operating and maintenance (O&M x/RES,DSM,CCT) $820 – $840 million Other operating expenses (depreciation and amortization, and taxes other than income taxes) $987 – $998 million Other income (pension and other post-retirement non-service credits, other income and other expense) $62 – $66 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC ~$64 million) $214 – $232 million Net income attributable to noncontrolling interests $17 million Effective tax rate 13.5% Average diluted common shares outstanding 113.5 million EPS Guidance $3.90 – $4.10

Arizona remains among the fastest growing states in the U.S. 14 Annual Employment Growth Last Three Years1 Steady Housing Growth2 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20 '21 Single Family & Multifamily Housing Permits Maricopa County 8,425 43,378 2 Maricopa County population 4.5M, 62% of state population1 2019-2021 National Arizona (1)% 1% 18% CAGR Second Quarter 2022

Best-in-class service territory supports high tech growth and economic development 15 Our Approach: Focus on Four Main Areas Supports Influx of Manufacturing and Data Centers – Examples • Business attraction and expansion • Community development • Entrepreneurial support • Infrastructure support • Taiwan Semiconductor Began building $12B factory • Chang Chun Petrochemical Building 250k sq ft facility • Williams-Sonoma Leased 1.2M sq ft facility • Nestle USA Building 625k sq ft facility • KORE Power Building 1M sq facility • Kohler Co. Building 1M sq ft facility Data centers are projected to create up to 640 MW of capacity needs by 2035 Second Quarter 2022

A clear plan for clean energy transition 16 Progress Towards Meeting Clean Energy Commitment1 Pathway 2005 2019 2030 2050 Contracted for nearly 1,600 MW of clean energy and storage to be in service for APS customers by end of 2024 Issued All-Source RFP which seeks 1,000 – 1,500 MWs of resources, including up to 600 – 800 MWs of renewable resources to be in service from 2025 – 2027 Charted course for healthy mix of APS-owned and third party- owned assets, to be continued through future planned RFPs 24% 50% 65% 100% 1 Since January 2020 Second Quarter 2022

Clean Energy Commitment – ~1,600MW in development since 2020 Second Quarter 202217 Robust, Diverse Procurement Activity Energy Storage • 201 MW APS-owned resources to retrofit entire fleet of AZ Sun facilities • 300 MW under two long-term PPAs • All resources to be in service between 2022 and 2024 Solar • 150 MW owned by APS and sited near Redhawk generating facility • 160 MW under two long-term PPAs • All resources to be in service in 2023 Solar + Storage • 275 MW under two long-term innovative tolling PPAs • Resources to be in service in 2023 and 2024 Wind • 438 MW under two long-term PPAs • Resources to be in service by 2023 Demand Response • 75 MW under 5-year load management agreement; service began in 2021 • APS can call up to 18 load reduction events between June and September annually

2022 Planned Outage schedule Second Quarter 202218 Coal, Nuclear and Large Gas Planned Outages Q1 Q2 Q4 Plant Unit Duration in Days Plant Unit Duration in Days Plant Unit Estimated Duration in Days N/A N/A N/A Palo Verde 1 35 Palo Verde 3 30

$1 $26 Q1 Q2 Q3 Q4 Gross margin effects of weather Second Quarter 202219 Variances vs. Normal$ in millions pretax 2022 $26 Million All periods recalculated to current 10-year rolling average (2011 – 2020). Numbers may not foot due to rounding.

Renewable Energy & Demand Side Management expenses1 Second Quarter 202220 $7 $6 $10 $13 $10 $4 $11 $12 $18 $13 $13 $16 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Demand Side Management Renewable Energy 2021 $89 Million 1 Renewable energy and demand side management expenses are offset by adjustment mechanisms. 2022 $43 Million Numbers may not foot due to rounding.

Residential PV applications1 Second Quarter 202221 1Monthly data equals applications received minus cancelled applications. As of June 30, 2022 approximately 145,122 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling approximately 1,239 MWdc of installed capacity. Excludes APS Solar Partner Program residential PV systems. Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Solar water heaters can also be found on the site but are not included in the chart above Residential DG (MWdc) Annual Additions 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2019 Applications 2020 Applications 2021 Applications 2022 Applications 122 139 169 101 2019 2020 2021 2022

Our credit ratings support growth opportunities 22 Corporate Ratings Senior Unsecured Ratings Short-Term Ratings Outlook APS1 Moody’s A3 A3 P-2 Negative S&P BBB+ BBB+ A-2 Negative Fitch BBB+ A- F2 Negative Pinnacle West1 Moody’s Baa1 Baa1 P-2 Negative S&P BBB+ BBB A-2 Negative Fitch BBB+ BBB+ F2 Negative Balance Sheet Targets • Strong investment grade credit ratings • APS equity layer >50% • FFO/Debt range of 16%-18% 1 We are disclosing credit ratings to enhance understanding of our sources of liquidity and the effects of our ratings on our costs of funds. Ratings are as of August 3, 2022. Second Quarter 2022

Regulatory 2022 key dates Second Quarter 202223 ACC Key Dates / Docket # Q1 Q2 Q3 Q4 Power Supply Adjustor (PSA): E-01345A-19-0236 Effective Feb 1 Lost Fixed Cost Recovery: E-01345A-22-0042 Filed Feb 15 Approved May 18 and effective Jun 1 Transmission Cost Adjustor: E-01345A-19-0236 Effective Jun 1 2022 DSM/EE Implementation Plan: E-01345A-21-0087 2022 RES Implementation Plan: E-01345A-21-0240 Approved May 18 and effective Jun 1 2019 Rate Case: E-01345A-19-0236 Court of Appeals in process; Filed opening brief Filed reply brief at Court of Appeals New TOU Hours to be implemented: Sep 1 Resource Planning and Procurement: E-00000V-19-0034 IRP Acknowledged Feb 10 Resource Comparison Proxy (RCP): E-01345A-22-0105 Approved July 12 and will be effective Sep 1 Rulemaking Requiring All-Source RFPs: RE-00000A-22-0029 Proposed Termination of Service Rule Modifications: RU-00000A-19-0132 Effective Apr 18

Components and Key Drivers of Benefit Costs1 Second Quarter 202224 Service Cost (a cost that increases Benefit Cost): • When discount rates decrease Service Cost increases and Benefit Cost increases (and vice versa) • Not impacted by asset assumptions Interest Cost (a cost that increases Benefit Cost): • When discount rates increase Interest Cost increases and Benefit Cost increases (and vice versa) • Not impacted by asset assumptions Expected Return on Plan Assets (an offset that decreases Benefit Cost): • Expected Return on Plan Assets increases and lowers Benefit Cost when (and vice versa): ▪ Future year beginning assets increase (e.g., fixed income assets increase when interest rates / yields decrease) ▪ The future year expected return on assets percentage increases (e.g., when interest rates / yields increase the future expected return percentage on fixed income assets increases) Amortization of Prior Service Credit (an offset that decreases Benefit Cost): • Not impacted by changes in discount rates or asset assumptions Amortization of Actuarial Losses (a cost that increases Benefit Cost; the opposite would be true for Actuarial Gains): • Increases when (and vice versa): ▪ Actual dollar return on plan assets is less than the expected return on plan assets (e.g., when fixed income assets decrease due to an increase in interest rates / yields) ▪ Liability increases (e.g., when discount rates decrease) • Note that only the net actuarial cumulative gain or loss is applied to the corridor 1 Represents some of the primary components of benefit cost, being disclosed to enhance the understanding of the key drivers; however, these components and drivers may not exhaustively account for all factors that comprise benefit cost in a given period. Benefit cost components are sensitive to changes in interest rates and market returns, often with offsetting impacts from various drivers. The sensitivity of benefit costs to changing interest rates and market returns can not necessarily be extrapolated. While increases in discount rates impact benefit costs, these impacts are less sensitive and impactful to benefit costs the further from 0% the discount rate moves.

Consolidated statistics1 Second Quarter 202225 3 Months Ended June 30 Numbers may not foot due to rounding. 3 Months Ended June 30 1 Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, for the year ended December 31, 2021 compared with the prior-year period increased 4.2%, which reflects a correction to 2020 commercial and industrial customer sales volumes of 111 GWh. 3 Months Ended June 30, 6 Months Ended June 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential $ 538 $ 532 $ 6 $ 905 $ 873 $ 32 Business 463 421 42 822 736 86 Total Retail 1,000 953 48 1,727 1,608 119 Sales for Resale (Wholesale) 30 18 12 59 36 23 Transmission for Others 29 23 7 55 42 13 Other Miscellaneous Services 2 7 (5) 4 11 (7) Total Operating Revenues $ 1,062 $ 1,000 $ 61 $ 1,845 $ 1,697 $ 148 ELECTRIC SALES (GWH) Retail Residential 3,786 3,799 (13) 6,435 6,380 55 Business 4,029 3,821 208 7,333 6,965 369 Total Retail Sales 7,815 7,620 194 13,768 13,345 423 Sales for Resale (Wholesale) 541 474 66 1,227 1,109 118 Total Electric Sales 8,355 8,094 261 14,995 14,454 542 RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 3,570 3,548 23 6,214 6,101 113 Business 3,970 3,759 211 7,285 6,913 372 Total Retail Sales 7,540 7,307 234 13,499 13,014 485 Retail sales (GWH) (% over prior year) 3.2% 5.5% 3.7% 3.1% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,197,089 1,172,488 24,602 1,197,432 1,171,410 26,022 Business 141,059 140,024 1,035 140,945 139,762 1,183 Total Retail 1,338,149 1,312,512 25,637 1,338,377 1,311,172 27,205 Wholesale Customers 54 46 8 54 43 11 Total Customers 1,338,203 1,312,558 25,645 1,338,430 1,311,215 27,216 Total Customer Growth (% over prior year) 2.0% 2.3% 2.1% 2.2% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 2,983 3,026 (43) 5,189 5,208 (19) Business 28,145 26,846 1,299 51,686 49,462 2,224

Consolidated statistics Second Quarter 202226 Numbers may not foot due to rounding. 3 Months Ended June 30 3 Months Ended June 30, 6 Months Ended June 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) ENERGY SOURCES (GWH) Generation Production Nuclear 2,192 2,079 113 4,589 4,538 51 Coal 1,832 1,201 630 3,661 2,535 1,126 Gas, Oil and Other 2,098 2,661 (563) 3,637 4,588 (951) Renewables 181 200 (19) 297 337 (40) Total Generation Production 6,302 6,141 161 12,184 11,998 186 Purchased Power - - Conventional 1,395 1,633 (238) 1,904 1,996 (92) Resales 186 140 46 191 145 45 Renewables 739 650 88 1,373 1,192 181 Total Purchased Power 2,320 2,423 (103) 3,468 3,333 135 Total Energy Sources 8,622 8,565 58 15,652 15,331 321 POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 88% 83% 5% 92% 91% 1% Coal 62% 41% 21% 62% 43% 19% Gas, Oil and Other 27% 34% (7)% 23% 29% (6)% Solar 36% 40% (4)% 30% 34% (4)% System Average 46% 45% 1% 44% 44% 1% 3 Months Ended June 30, 6 Months Ended June 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days 570 575 (5) 570 575 (5) Heating Degree-Days 3 - 3 454 506 (52) Average Humidity 17% 15% 2% 17% 15% 2% 10-Year Averages (2011 - 2020) Cooling Degree-Days 504 504 - 504 504 - Heating Degree-Days 5 5 448 448 - Average Humidity 17% 17% - 0% 0% -