POWERING GROWTH DELIVERING VALUE Third Quarter 2022 Results November 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 September 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. Third Quarter 2022

3rd Quarter negative prior rate case impacts partially offset by weather 3 3rd Quarter 2022 vs. 3rd Quarter 2021 3Q 2021 3Q 2022 $3.00 $2.88 Operating Revenue less Fuel and Purchased Power1 $0.22 O&M1 & 2 $(0.13) D&A2 $(0.18) Operating Revenue less Fuel and Purchased Power Federal Tax Reform3 Weather Other Transmission LFCR GRC Base Rate Impact $ $ $ $ $ $ 0.34 0.23 0.05 0.04 (0.10) (0.34) Pension & OPEB Non- service Credits, net $(0.02) Other, net2 $(0.09) 1 Includes costs and offsetting operating revenues associated with renewable energy and demand side management programs, see slide 23 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 prior rate case. 4 The Q3 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. Third Quarter 2022 Other Taxes2 $0.03 Interest, net AFUDC $(0.05) Income Taxes4 $0.10

2022 EPS guidance Third Quarter 20224 Key Factors and Assumptions as of November 3, 2022 2022 Adjusted gross margin (operating revenues, net of fuel and purchased power expenses, x/RES,DSM,CCT) $2.59 – $2.61 billion • Retail customer growth about 1.5-2.5% • Weather-normalized retail electricity sales volume 2.0-3.0% 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) $880 – $895 million Other operating expenses (depreciation and amortization, and taxes other than income taxes) $977 – $979 million Other income (pension and other post-retirement non-service credits, other income and other expense) $59 – $63 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC ~$64 million) $213 – $215 million Net income attributable to noncontrolling interests $17 million Effective tax rate 13.7% Average diluted common shares outstanding 113.4 million EPS Guidance $4.20 – $4.35

Key drivers for EPS guidance1 1 • Retail customer growth 1.5%-2.5% • Weather-normalized retail electricity sales growth of 2%-3% • Transmission revenues • Operations and maintenance • Depreciation and amortization Third Quarter 20225 2022 key drivers • 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 November 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 weather-normalized 5-year compound annual growth rate projections from 2022-2026 3 Forecasted guidance range from 2022-2024

2022 APS Rate Case Application 1 Third Quarter 20226 Overview of Rate Increase Request ($ in Millions) Key Components1 • Filed October 28, 2022 • APS has requested rates become effective December 1, 2023 • Docket Number: E-01345A-22-0144 • Additional details, including filing, can be found at http://www.pinnaclewest.com/investors Additional Details Rate Base Growth $130 12 Months Post Test Year Plant 140 Weighted Average Cost of Capital of 7.17% 78 1% Fair Value Increment 78 New Customer Programs, Coal Community Transition and Other 34 Total Revenue Request $460 Customer Net Bill Impact on Day 1 13.6% 1Numbers may not foot due to rounding

2022 APS Rate Case Application 1 • Eliminate the Environmental Improvement Surcharge and collect costs through base rates • Eliminate the Lost Fixed Cost Recovery Mechanism and collect costs through base rates and the Demand Side Management Adjustor Charge • Modify the Renewable Energy Adjustor Charge to include recovery of capital carrying costs of APS owned renewable and storage resources • Modify the performance incentive in the Demand Side Management Adjustor Charge • Maintain the Power Supply Adjustor to ensure timely recovery of fuel and purchase power costs • Maintain as inactive the Tax Expense Adjustor Mechanism • Maintain the Transmission Cost Adjustment mechanism Third Quarter 20227 Adjustment Mechanisms Overview • Enhance the current limited income program to include a second tier to provide an additional discount for customers with a greater need • Waiver of credit card and payment fees New Customer Program Proposals

2022 APS Rate Case Application Third Quarter 20228 Key Financials Test year ended June 30, 2022 Total Rate Base - Adjusted $13.1 Billion ACC Rate Base - Adjusted $10.5 Billion Embedded Long-Term Cost of Debt 3.85% Allowed Return on Equity 10.25% Capital Structure Long-term debt 48.07% Common equity 51.93% Base Fuel Rate (¢/kWh) 3.8321 Post-test year plant period 12 months

$170 $165 $185 $190 $595 $560 $530 $500 $263 $210 $210 $210 $260 $350 $330 $560 $214 $240 $270 $190 2021 2022E 2023E 2024E Other Generation Clean Generation Transmission Distribution Other APS Total 2022-2024 $4.7B $1.50B $1.53B $1.53B $1.65B 9 Managed capital plan to support customer growth, reliability, and clean transition 2022–2024 as disclosed in the Third Quarter 2022 Form 10-Q. Third Quarter 2022

Total Approved Rate BaseAPS Rate Base Growth Guidance Year-End Steady rate base growth Third Quarter 202210 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 $9.8 $11.2 $1.8 $1.9 $2.4 2020 2021 2022 2023 2024 $11.7 Projected 5-6% Annual FERC ACC $10.9 $13.6

Our goal continues to be declining O&M per MWh 11 O&M per MWh Total O&M1 2021: $865M 2022: $880M-$895M 1 Total O&M amounts exclude RES/DSM, and include planned outage amounts of $54M in 2021 and $40M-$50M in 2022. Third Quarter 2022 $29/MWh

Forecasted sources of capital to fund investments through 2024 No plans to issue equity before end of next rate case 12 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. Third Quarter 2022 Total Capital Investment PNW Equity/ Alternatives

Strong balance sheet with attractive long-term debt maturity profile1 13 $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 September 30, 2022 Third Quarter 2022 1 Does not include debt at Bright Canyon Energy.

We continue to make progress towards key deliverables Third Quarter 202214 ➢ 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 ✓ Oral Arguments set for November 30 ➢ 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 ✓ Filed rate case October 28, 2022 (Docket No. E-01345A-22-0144) ➢ Work with stakeholders on common issues ✓ Received approval of Customer Education and Outreach Plan ➢ Flat total O&M and declining O&M per MWh ✓ Declining O&M per MWh despite inflationary environment ➢ Continue progress towards Clean Energy Commitment ➢ Continue support in attracting high tech growth and economic development

APPENDIX

Arizona remains among the fastest growing states in the U.S. 16 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 Third Quarter 2022

Best-in-class service territory supports high tech growth and economic development 17 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 Third Quarter 2022

A clear plan for clean energy transition 18 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 Third Quarter 2022

Clean Energy Commitment – ~1,600MW in development since 2020 Third Quarter 202219 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 Third Quarter 202220 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 35

2023 Planned Outage schedule Third Quarter 202221 Coal, Nuclear and Large Gas Planned Outages Q1 Q2 Q4 Plant Unit Estimated Duration in Days Plant Unit Estimated Duration in Days Plant Unit Estimated Duration in Days N/A N/A N/A Palo Verde 2 35 Palo Verde 1 35 Redhawk CC1 34

$1 $26 $6 Q1 Q2 Q3 Q4 Gross margin effects of weather Third Quarter 202222 Variances vs. Normal$ in millions pretax 2022 $33 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 Third Quarter 202223 $7 $6 $10 $13 $10 $4 $12 $11 $12 $18 $13 $13 $16 $18 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 $73 Million Numbers may not foot due to rounding.

Residential PV applications1 Third Quarter 202224 1Monthly data equals applications received minus cancelled applications. As of September 30, 2022 approximately 147,466 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling approximately 1,273 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 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 122 139 169 149 2019 2020 2021 2022

Our credit ratings support growth opportunities 25 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 November 3, 2022. Third Quarter 2022

Regulatory 2022 key dates Third Quarter 202226 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 implemented: Sep 1 Court of Appeals oral arguments Nov 30 Resource Planning and Procurement: E-00000V-19-0034 IRP acknowledged Feb 10 Resource Comparison Proxy (RCP): E-01345A-22-0105 Approved July 12 and effective Sep 1 2022 Rate Case: E-01345A-22-0144 Application filed Oct 28 2022 Financing Application: E-01345A-22-0083 Application filed April 6

Pension & Other Post Retirement Benefits (“OPEB”) 27 Third 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

Components and Key Drivers of Benefit Costs1 Third Quarter 202228 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 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 Third Quarter 202229 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 September 30, 9 Months Ended September 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential $ 743 $ 682 61 $ 1,648 $ 1,554 $ 94 Business 548 481 67 1,370 1,216 154 Total Retail 1,291 1,163 128 3,018 2,771 247 Sales for Resale (Wholesale) 140 108 31 198 144 54 Transmission for Others 36 36 0 91 78 14 Other Miscellaneous Services 3 1 1 7 13 (5) Total Electric Operating Revenues $ 1,470 $ 1,308 162 $ 3,315 $ 3,005 $ 310 ELECTRIC SALES (GWH) Retail Residential 5,389 5,188 201 11,824 11,569 256 Business 4,768 4,478 290 12,101 11,442 658 Total Retail 10,157 9,666 491 23,925 23,011 914 Sales for Resale (Wholesale) 1,376 1,701 (326) 2,603 2,810 (207) Total Electric Sales 11,532 11,368 165 26,528 25,821 707 RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 5,326 5,416 (90) 11,539 11,517 22 Business 4,763 4,542 221 12,047 11,454 593 Total Retail Sales 10,088 9,958 131 23,587 22,972 615 Retail sales (GWH) (% over prior year) 1.3% 4.0% 2.7% 3.5% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,202,870 1,178,117 24,753 1,199,245 1,173,646 25,599 Business 141,619 140,013 1,606 141,169 139,845 1,324 Total Retail 1,344,489 1,318,130 26,360 1,340,414 1,313,491 26,923 Wholesale Customers 56 50 6 54 45 9 Total Customers 1,344,545 1,318,179 26,366 1,340,469 1,313,536 26,932 Total Customer Growth (% over prior year) 2.0% 2.3% 2.1% 2.2% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 4,428 4,597 (170) 9,622 9,813 (191) Business 33,630 32,437 1,193 85,340 81,908 3,432

Consolidated statistics Third Quarter 202230 Numbers may not foot due to rounding. 3 Months Ended June 30 3 Months Ended September 30, 9 Months Ended September 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) ENERGY SOURCES (GWH) Generation Production Nuclear 2,532 2,488 44 7,121 7,026 94 Coal 2,591 2,349 242 6,252 4,884 1,369 Gas, Oil and Other 2,814 3,096 (282) 6,451 7,684 (1,233) Renewables 155 169 (14) 452 506 (54) Total Generation Production 8,092 8,102 (10) 20,276 20,100 176 Purchased Power - - Conventional 2,389 3,083 (693) 4,294 5,079 (785) Resales 1,091 1,041 49 1,281 1,187 95 Renewables 493 468 25 1,866 1,660 206 Total Purchased Power 3,973 4,592 (619) 7,441 7,925 (484) Total Energy Sources 12,066 12,695 (629) 27,717 28,026 (308) POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 100% 98% 2% 95% 94% 1% Coal 86% 78% 8% 70% 55% 15% Gas, Oil and Other 36% 39% (4)% 27% 33% (5)% Solar 31% 34% (3)% 30% 34% (4)% System Average 58% 58% (0)% 49% 49% 0% 3 Months Ended September 30, 9 Months Ended September 30, 2022 2021 Incr (Decr) 2022 2021 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days 1,266 1,105 161 1,836 1,680 156 Heating Degree-Days Not Applic. Not Applic. 454 506 (52) Average Humidity 35% 38% (3)% 28% 29% (1)% 10-Year Averages (2011 - 2020) Cooling Degree-Days 1,256 1,256 - 1,761 1,761 - Heating Degree-Days Not Applic. Not Applic. 448 448 - Average Humidity 30% 30% - 25% 25% -