Renewed, Reliable and Resilient Second-Quarter Financial Results August 6, 2025

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: uncertainties associated with the current and future economic environment, including economic growth rates, labor market conditions, tariffs, inflation, supply chain delays, increased expenses, volatile capital markets, or other unpredictable effects; current and future economic conditions in Arizona, such as the housing market and overall business and regulatory environment; our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels; the direct or indirect effect on our facilities or business from cybersecurity threats or occurrences; 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 tax, 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 investment; the ability of APS to meet renewable energy and energy efficiency mandates and recover related costs; the ability of APS to achieve its clean energy goal to be carbon-neutral by 2050 and, if this goal is 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; data security breaches, 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, including as a result of delays in the development and application of new technologies; the cost of debt, including increased cost as a result of rising interest rates, and equity capital and our ability to access capital markets when required; 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, captive insurance cell, coal mine reclamation escrow, 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 facilities and system conditions and operating costs; our ability to meet the anticipated future need for additional generation and associated transmission facilities in our region; the willingness or ability of counterparties, power plant participants and power plant landowners 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 the most recent Pinnacle West/APS Form 10-K along with other public filings with the Securities and Exchange Commission, 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. Forward Looking Statements

$0.06 ($0.09) ($0.02) $0.01 ($0.06) ($0.08) $1.76 $1.58 Q2 2025 vs Q2 2024 Operating Revenue less Fuel and Purchased Power Transmission $ 0.10 Sales/Usage $ 0.08 Other $ 0.03 Weather $ (0.15) Q2 2024 Q2 2025 1 Includes costs and offsetting operating revenues associated with renewable energy and demand side management programs, see slide 24 for more information. 2 All other includes share dilution, other taxes, income taxes, other, net and rounding. 3 Income taxes are negatively impacted this quarter due to the one-time benefit recognized in Q2 2024 related to the Los Alamitos ITC purchase and the timing of when other on-going permanent tax items and credits are recognized through the effective tax rate. Operating Revenue less Fuel and Purchased Power1 O&M1 D&A Pension & OPEB non- service credits, net Interest, net AFUDC All other2 3 Second-Quarter results All Other El Dorado investment $ 0.04 Income taxes3 $ (0.04) Share dilution $ (0.08)

Key Factors and Assumptions (as of August 6, 2025) 2025 Adjusted gross margin (operating revenues, net of fuel and purchased power expenses, x/RES,DSM,CCT)1 $3.13 – $3.19 billion • Retail customer growth of 1.5%-2.5% • Weather-normalized retail electricity sales growth of 4.0%-6.0% • Includes 3.0%-5.0% contribution to sales growth of new large manufacturing facilities and several large data centers • Assumes normal weather Adjusted operating and maintenance expense (O&M x/RES,DSM,CCT)1 $965 – $985 million Other operating expenses (depreciation and amortization, and taxes other than income taxes) $1.16 – $1.18 billion Other income (pension and other post-retirement non-service credits, other income and other expense) $0 – $6 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC ~$120 million) $350 – $370 million Net income attributable to noncontrolling interests $17 million Effective tax rate 13.25% – 13.75% Average diluted common shares outstanding 122.3 million EPS Guidance $4.40 – $4.60 1 Excludes costs and offsetting operating revenues associated with renewable energy and demand side management programs. For reconciliation, see slide 24. 4 2025 EPS guidance

2025 EPS guidance of $4.40-$4.60 key drivers1  Retail customer growth of 1.5%-2.5%  Depreciation, amortization and property taxes due to higher plant in service  Weather-normalized retail electricity sales growth of 4%-6% (includes 3%-5% from large C&I)  2025 normal weather  Transmission revenue  Financing costs (debt & equity)  Operations and maintenance  Pension/OPEB non-service costs2  2024 BCE gain on sale Long-term guidance and key drivers1,2 • Long-term EPS growth target of 5%-7% off original 2024 midpoint • Retail customer growth of 1.5%-2.5% • Weather-normalized retail electricity sales growth of 4%-6% (includes 3%-5% from large C&I customers) 4.2% 2.4% 1.5% 5.7% 4.0%-6.0% 0% 1% 2% 3% 4% 5% 6% 7% 8% '21 '22 '23 '24 '25E Total Sales Growth 5 1 Arrows represent expected comparative year-over-year impact of each driver on earnings. 2 Primarily due to roll-off of positive amortization of prior service credits. Key drivers & assumptions for 2025 EPS guidance 1 Long-term EPS growth target based on the Company’s current weather normalized compound annual growth rate projections from 2024-2028. 2 Forecasted guidance range through 2027.

$7.80B $9.66B 2023-2026E 2024-2027E CapEx Profile $273 $380 $335 $275 $637 $665 $670 $675 $340 $450 $675 $750 $807 $905 $870 $950 2024 2025E 2026E 2027E APS Total 2024-2027 $9.66B Generation Transmission Distribution Other $2.06B $2.40B $2.55B $2.65B Source: 2025-2027 as disclosed in the Second Quarter 2025 Form 10-Q Q4 2023 Today 6 Capital plan to support reliability and continued growth within our service territory

Current Approved Rate Base and Test Year Detail End-of-Year Rate Base and Growth Guidance1 ACC FERC Rate Effective Date 03/08/2024 06/01/2025 Test Year Ended 6/30/20221 12/31/2024 Equity Layer 51.93% 52.28% Allowed ROE 9.55% 10.75% Rate Base $10.36B2 $2.47B $11.23 $12.23 $14.4 $2.12 $2.52 $3.2 2023 2024 2025 2026 2027 ACC FERC 7 Rate base $ in billions, rounded Projected 1 Guidance excludes CWIP amounts of $1.7B in 2023 and $3.0B-$3.5B in 2027. 2 Derived from APS annual update of formula transmission service rates. 3 Represents unadjusted ACC jurisdictional rate base consistent with regulatory filings. 1 Adjusted to include post-test year plant in service through 06/30/2023. 2 Rate Base excludes $215M approved through Joint Resolution in Case No. E-01345A-19-0236. Generation spend through System Reliability Benefit Surcharge and transmission spend expected to total ~40% of tracked capital from 2024-2027 and help reduce regulatory lag Rate Base growing within our service territory

8 Operations & Maintenance Guidance • Reduced year-over-year core O&M excluding planned outages • Completed planned major outage in Q1 at Four Corners Unit 4 • Lean culture and declining O&M per MWh goal We are focused on cost control and customer affordability $955 $910 - $920 $141 $150 - $160 $70 $55 - $65 2024 2025E O&M Guidance (millions) Planned Outages RES/DSM Core O&M

Approx. $3.6B Cash from Operations1 Total Capital Investment $2.5B-$2.7B APS Debt2 $500M-700M PNW Debt2 1 Cash from operations is net of shareholder dividends. 2 APS and PNW debt issuance is net of maturities. • External equity to support balanced APS capital structure and expanded, accretive capital investment • Equity needs < prior targeted 40% of new capital • Financing plan consistent with balance sheet targets • In May 2025 PNW issued $800M unsecured bonds; proceeds used to pay off $500M PNW 2025 maturity and $300M APS 2025 maturity Funding Strategy 2025-2027 Financing Plan Approx. $7.6B $700-900M PNW Equity 9 Optimized financing plan to support balanced capital structure Feb. 2024 Forward Sale Priced Settled Dec. 2024 Partial Settlement $725M $345M Forward ATM Program ($900M) Priced Settled ATM Program $100M $0 ATM program: PNW may sell up to $900M of common stock Completed Equity

Balance Sheet Targets • Solid investment-grade credit ratings • APS equity layer >50% • PNW FFO/Debt range of 14%-16% Corporate Ratings Senior Unsecured Ratings Short-Term Ratings Outlook APS Moody’s Baa1 Baa1 P-2 Stable S&P BBB+ BBB+ A-2 Stable Fitch BBB+ A- F2 Stable Pinnacle West Moody’s Baa2 Baa2 P-2 Stable S&P BBB+ BBB A-2 Stable Fitch BBB BBB F3 Stable 10 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 July 28, 2025. We are focused on maintaining healthy credit ratings to support affordable growth1

$0 $200 $400 $600 $800 $1,000 $1,200 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050 APS Fixed APS Floating PNW Fixed PNW Floating($millions) As of June 30, 2025 11 Debt maturity profile shows well managed and stable financing plan

Appendix

13 2025 APS rate case application Overview of rate request ($ in millions) key components Rate Base Growth $208 12 months Post-test Year Plant $82 Fair Value Increment $101 WACC (7.63%) $129 Other (Base fuel, depreciation study, etc.) $143 Total Revenue Requirement $662 Adjustor Transfers $(82) Net Revenue Increase $580 Customer Net Revenue Impact on Day 1 13.99% Additional details • APS has requested rates become effective in the second half of 2026 • Docket number: E-01345A-25-0105 • Additional details, including filing, can be found at http://www.pinnaclewest.com/investors Numbers may not foot due to rounding.

14 2025 APS rate case application Overview of rate request ($ in millions) key components Test Year Ended December 31, 2024 Total Rate Base - Adjusted $15.3B ACC Rate Base - Adjusted $12.5B Embedded Long-Term Cost of Debt 4.26% Allowed Return on Equity 10.70% ROE Band for Formula Rate +/- 20bps Capital Structure Long-Term Debt 47.65% Common Equity 52.35% Base Fuel Rate (¢/kWh) 4.3881¢/kWh Post-Test Year Plant period 12 months Proposed rate design modifications • Direct assignment of generation costs to ensure extra high load factor customers pay for the resources they require • Align rates with costs to move classes closer to their cost of service which supports small and medium sized businesses • Ensure growth pays for growth and offers significant customer protections

15 2025 APS rate case application Formula Rate Adjustment Mechanism (FRAM) proposal • Historic test year, with authorized ROE and capital structure approved in most recent rate case • Inclusion of 12 months projected plant • System Reliability Benefit costs transferred into each formula reset • No rate adjustment if actual ROE falls within +/- 20 bps of authorized ROE • Revenue surplus/deficiency allocated based on ACC jurisdictional cost of service results FRAM proposed schedule ACC filing of Annual Update On or before July 31 Last day for data requests and to submit informal challenge(s) August 12 Last day for Company responses to informal challenge(s) August 26 Informal challenge(s) resolution deadline August 31 Rate effective date First September billing cycle Last day for data requests and to submit formal challenge(s) September 22 Last day for Company responses to formal challenge(s) October 6 Staff Report (if no hearing) October 31 Commission Decision December 1

16 • Projects that compete on cost and reliability from All-Source Request for Proposals • Determines prudency of new generation between general rate cases • Included in rates approximately 180 days after in service with Commission approval • Recovery at prevailing WACC less 100bps until future rate case • Traditional AFUDC treatment until asset is in service System Reliability Benefit Surcharge Key Features Continued Progress on Potential SRB Opportunities Proposed Project MWs Est. In-Service Status Sundance Expansion 90 2026 In Construction Ironwood Solar 168 2026 In Construction Redhawk Expansion 397 2028 Contracted SRB will expand our capacity to self-build generation to meet customer need with reduced lag

Source: APS 2024-2033 Ten Year Transmission System Plan Support customer growth Access to markets Increase resiliency 17 Making progress on multiple strategic transmission opportunities as part of 2025-2027 capital expenditure plan Line Length (miles) Voltage Status Est. In- Service Sundance to Milligan 22 230 kV Siting in progress 2027 Ocotillo to Pinnacle Peak 25 230 kV Siting in progress 2029 Panda to Freedom 40 230 kV Siting in progress 2029 Jojoba to Rudd 25 500 kV Siting in progress 2030 Transmission expansion will drive increased capital investment

2.3% 2.4% 2.2% 2.1% 2.1% 1.5%-2.5% 0% 1% 2% 3% 2020 2021 2022 2023 2024 2025E Residential Customer Growth1 APS Residential Growth Natn'l Avg.-Residential 18 • Phoenix housing is affordable compared to major cities in the region • U.S. Census ranked Maricopa County third among U.S. counties for growth • Phoenix is ranked #1 out of 15 top growth markets for manufacturing by Newmark Group, a global real estate firm • Arizona State University ranked #1 in Innovation for 10th straight year by U.S. News and World Report • Phoenix remains #1 as best positioned industrial real estate market by Commercial Café Report Arizona economy continues to be robust and attractive 1 National average from 2024 Itron Annual Energy Survey Report. Arizona continues to be an attractive service territory with strong customer growth - 10,000 20,000 30,000 40,000 2012 2016 2020 2024 New APS Customer Meter Sets

Source: Arizona Commerce Authority 19 Arizona’s commercial and industrial growth is diverse

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 2022 Applications 2023 Applications 2024 Applications 2025 Applications 200 216 108 40 2022 2023 2024 2025 Monthly data equals applications received minus cancelled applications. As of June 30, 2025, approximately 188,955 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling approximately 1,696 MWdc of installed capacity. Excludes APS Solar Partner Program, APS Solar Communities, and Flagstaff Community Partnership Program. Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Residential DG (MWdc) Annual Additions 20 Residential PV Applications

$17 $14 $18 $18 $18 $16 $16 $19 $26 $12 $15 $18 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Renewable Energy Demand Side Management 2024 $141 Million 2025 $67 Million 1 Renewable Energy and Demand Side Management expenses are substantially offset by adjustment mechanisms. Numbers may not foot due to rounding. ($ in millions pretax) 21 Renewable Energy & Demand Side Management expenses1

($3) $14 Q1 Q2 Q3 Q4 Variances vs. Normal All periods recalculated to current 10-year rolling average (2014 – 2023). Numbers may not foot due to rounding. ($ in millions pretax) 2025 Total Weather Impact: $12 Million 22 2025 gross margin effects of weather

Q1 Plant Unit Actual Duration in Days Redhawk CC2 60 Four Corners 4 72 Coal, Nuclear and Large Gas Planned Outages 23 2025 Planned Outage Schedule Q2 Plant Unit Actual Duration in Days Palo Verde1 1 42 Four Corners 4 12 Q4 Plant Unit Estimated Duration in Days Palo Verde 3 36 1 Outage began at end of Q1

2024 Actual3 2025 Guidance3 Operating revenues1 $5.12 billion $5.22 - $5.32 billion Fuel and purchased power expenses1 $1.82 billion $1.93 - $1.97 billion Gross Margin $3.30 billion $3.29 - $3.35 billion Adjustments: Renewable energy and demand side management programs2 $149 million $150 - $160 million Adjusted gross margin $3.15 billion $3.13 - $3.19 billion Operations and maintenance1 $1.17 billion $1.12 - $1.14 billion Adjustments: Renewable energy and demand side management programs2 $141 million $150 - $160 million Adjusted operations and maintenance $1.02 billion $965 - $985 million 24 1 Line items from Consolidated Statements of Income. 2 Includes $3.3M for CCT (Coal Community Transition) in 2024 which is recovered through REAC (Renewable Energy Adjustment Charge). 3 Numbers may not foot due to rounding. Non-GAAP Measure Reconciliation

Case/Docket # Q1 Q2 Q3 Q4 2025 Rate Case E-01345A-25-0105: Notice of Intent filed May 15 Application filed June 13 ACC Letter of Sufficiency filed July 14 Power Supply Adjustor (PSA) E-01345A-22-0144: 2025 PSA rate reset effective March 1 PSA reset to be filed Nov. 26 Transmission Cost Adjustor E-01345A-22-0144: Filed May 15; effective June 1 Lost Fixed Cost Recovery E-01345A-25-XXXX: 2025 LFCR filed July 31 2025 LFCR effective Nov. 1 (if approved) ACC Inquiry Into Nuclear Issues E-00000A-25-0026: ACC Nuclear Issues Workshop held May 21 Resource Comparison Proxy E-01345A-24-0095: Updated RCP calculation filed May 1 RCP Update effective Sep. 1 Test Year Rules (Regulatory Lag) AU-00000A-23-0012: ACC adopted Formula Rates Policy Statement Dec. 13, 2024 2025 Summer Preparedness AU-99999A-25-0004: 2025 Summer Preparedness Workshop held Apr. 24 2026 RES Implementation Plan E-01345A-25-XXXX: 2026 RES plan filed July 1 2026 DSM Implementation Plan E-01345A-25-XXXX: 2026 DSM Plan 120-day extension request granted ACC Inquiry Into Natural Gas Infrastructure G-00000A-25-0029: Workshop scheduled August 26 25 2025 Key Regulatory Dates

26 Wildfire Mitigation Vegetation management Asset inspection Monitoring and awareness Operational mitigations • Comprehensive right- of-way clearance on maintained cycles • Defensible space around poles (DSAP) • Hazard tree program • Enhanced line patrols • Technology deployments • Drone use • Infra-red scans • Non-reclosing strategy • Public outreach program • Red Flag Warning protocols • Public Safety Power Shutoff (PSPS) • Dedicated team of meteorologists • Advanced fire modeling software • Cameras and weather stations • Federal & state agency partnerships Grid hardening investments • Ongoing distribution system upgrades • Mesh pole wrapping • Expulsion limiting fuses • Steel poles (if truck accessible) Internal: 18-person fire mitigation department engages across entire APS organization to plan and implement initiatives External: Member of multiple fire mitigation industry associations Independent third-party reviews of APS wildfire mitigation plan Our current practices are comprehensive and multi-faceted:

27 Consolidated Statistics * Includes reduction of accrued unbilled revenues in January 2025. Numbers may not foot due to rounding. 3 Months Ended June 30, 6 Months Ended June 30, 2025 2024 Incr (Decr) 2025 2024 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential $ 652 $ 658 $ (6) $ 1,101 $ 1,091 $ 10 Business 654 610 44 1,179 1,071 108 Total Retail 1,306 1,268 38 2,279* 2,162 117 Sales for Resale (Wholesale) 18 10 8 43 37 6 Transmission for Others 32 28 4 58 55 2 Other Miscellaneous Services 3 3 (0) 11 6 5 Total Operating Revenues $ 1,359 $ 1,309 $ 50 $ 2,391 $ 2,261 $ 130 ELECTRIC SALES (GWH) Retail Residential 3,688 3,805 (118) 6,356 6,572 (216) Business 4,840 4,536 303 8,878 8,346 532 Total Retail Sales 8,527 8,342 186 15,234 14,918 316 Sales for Resale (Wholesale) 904 788 115 1,991 1,688 302 Total Electric Sales 9,431 9,130 301 17,225 16,606 618 RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 3,576 3,509 67 6,280 6,276 4 Business 4,818 4,466 352 8,847 8,293 554 Total Retail Sales 8,394 7,975 418 15,126 14,569 557 Retail sales (GWH) (% over prior year) 5.2% 5.5% 3.8% 5.6% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,282,226 1,250,437 31,788 1,279,520 1,248,639 30,881 Business 145,834 143,611 2,223 145,489 143,644 1,845 Total Retail 1,428,060 1,394,048 34,011 1,425,009 1,392,283 32,726 Wholesale Customers 60 60 (0) 57 59 (3) Total Customers 1,428,120 1,394,109 34,011 1,425,065 1,392,342 32,723 Total Customer Growth (% over prior year) 2.4% 2.1% 2.4% 2.0% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 2,789 2,806 (17) 4,908 5,026 (119) Business 33,034 31,098 1,936 60,806 57,731 3,075

28 Consolidated Statistics Numbers may not foot due to rounding. 3 Months Ended June 30, 6 Months Ended June 30, 2025 2024 Incr (Decr) 2025 2024 Incr (Decr) ENERGY SOURCES (GWH) Generation Production Nuclear 2,139 2,192 (53) 4,647 4,741 (94) Coal 1,448 1,502 (53) 2,549 3,491 (942) Gas, Oil and Other 2,208 1,960 248 4,430 3,370 1,060 Renewables 295 354 (59) 475 584 (110) Total Generation Production 6,091 6,007 83 12,101 12,187 (86) Purchased Power Conventional 1,550 1,818 (268) 2,262 2,439 (176) Resales 248 258 (10) 288 298 (10) Renewables 1,922 1,222 700 3,414 2,050 1,364 Total Purchased Power 3,720 3,298 422 5,965 4,787 1,177 Total Energy Sources 9,811 9,306 506 18,066 16,974 1,092 POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 86% 88% (1)% 93% 95% (1)% Coal 50% 51% (1)% 43% 59% (15)% Gas, Oil and Other 28% 25% 3% 28% 21% 6% Solar 33% 43% (10)% 26% 36% (9)% System Average 43% 42% 0% 42% 43% (1)% 3 Months Ended June 30, 6 Months Ended June 30, 2025 2024 Incr (Decr) 2025 2024 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days 548 648 (100) 548 648 (100) Heating Degree-Days 10 20 (10) 416 496 (80) Average Humidity 17% 17% 0% 17% 17% 0% 10-Year Averages (2014 - 2023) Cooling Degree-Days 509 509 - 509 509 - Heating Degree-Days 3 3 449 449 - Average Humidity 17% 17% - 17% 17% -