EX-99.2 3 a3q2023earningsdeckfinal.htm EX-99.2
POWERING GROWTH DELIVERING VALUE Third Quarter 2023 Results November 2, 2023 1

Forward Looking Statements 2 This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings guidance and f inancial 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 current economic environment and its effects, such as lower economic growth, a tight labor market, inflation, supply chain delays, increased expenses, volatile capital markets, or other unpredictable effects; 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 investment; 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; the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, 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 the ability to access capital markets when required; environmental, economic, and other concerns surrounding coal-fired generation, including regulation of GHG 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 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 and 10-Q 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. Third Quarter 2023

3rd Quarter impacted by record summer heat 3 3rd Quarter 2023 vs. 3rd Quarter 2022 3Q 2022 3Q 2023 $2.88 $3.50 Operating Revenue less Fuel and Purchased Power1 $0.73 O&M1 $0.01 D&A $(0.09) Operating Revenue less Fuel and Purchased Power Weather LFCR 2019 GRC Appeal Outcome Other RES/DSM/EIS Transmission $ $ $ $ $ $ 0.38 0.14 0.14 0.05 0.04 (0.02) Pension & OPEB Non- service Credits, net $(0.10) 1 Includes costs and offsetting operating revenues associated with renewable energy and demand side management programs, see slides 19 & 30 for more information. 2 Income taxes are favorably impacted this quarter due to the timing of when permanent tax items and credits are recognized through the effective tax rate, as well as increased PTC for the Agave solar plant and increased ITC amortization for the AZ Sun Battery projects. Interest, net AFUDC $(0.14) Third Quarter 2023 Income & other taxes2 $0.13 Other, net $0.08

2023 EPS guidance Third Quarter 20234 Key Factors and Assumptions as of November 2, 2023 2023 Adjusted gross margin (operating revenues, net of fuel and purchased power expenses, x/RES,DSM,CCT)1 $2.72 – $2.77 billion • Retail customer growth of 1.5%-2.5% • Weather-normalized retail electricity sales growth of 1.0%-3.0% • Includes 1.0%-2.0% contribution to sales growth of new large manufacturing facilities and several large data centers • Assumes normal weather for balance of year forecast Adjusted operating and maintenance expense (O&M x/RES,DSM,CCT)1 $915 – $935 million Other operating expenses (depreciation and amortization, and taxes other than income taxes) $1.02 – $1.03 billion Other income (pension and other post-retirement non-service credits, other income and other expense) $43 – $48 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC ~$96 million) $265 – $285 million Net income attributable to noncontrolling interests $17 million Effective tax rate 12.8% – 13.3% Average diluted common shares outstanding 113.7 million EPS Guidance $4.10 – $4.30 1 Excludes costs and offsetting operating revenues associated with renewable energy and demand side management programs. For reconciliation, see slide 30.

Key drivers for EPS guidance1 1 Retail customer growth of 1.5%-2.5% Weather-normalized retail electricity sales growth of 1.0%-3.0% Transmission revenues LFCR 2019 Rate Case Appeal Outcome Third Quarter 20235 2023 EPS guidance of $4.10-$4.30 key drivers1,2 • Long-term EPS growth target of 5%-7%3 • Retail customer growth of 1.5%-2.5%4 • Weather-normalized retail electricity sales growth of 4.5%-6.5%4 1 Arrows represent expected comparative year-over-year impact of each driver on earnings. 2 As of November 2, 2023. Long-term guidance and key drivers  Depreciation, amortization and property taxes due to higher plant in service  Operations and maintenance expense  Interest expense  Pension and OPEB 3 Long-term EPS growth target based on the Company’s current weather-normalized 5-year compound annual growth rate projections from 2022-2026. 4 Forecasted guidance range through 2025.

$167 $265 $260 $255 $577 $590 $530 $530 $217 $315 $300 $300 $345 $325 $465 $520 $226 $305 $245 $245 2022 2023E 2024E 2025E Other Generation Clean Generation Transmission Distribution Other APS Total 2023-2025 $5.45B $1.53B $1.80B $1.80B $1.85B 6 Managed capital plan to support customer growth, reliability, and clean transition 2023–2025 as disclosed in the Third Quarter 2023 Form 10-Q. Third Quarter 2023

Approved Rate BaseTotal APS Rate Base Growth Guidance Year-End Steady rate base growth 7 ACC FERC Rate Effective Date 12/01/2021 6/1/2023 Test Year Ended 06/30/20191 12/31/2022 Rate Base $8.6B2 $2.0B Equity Layer 54.7% 50.3% Allowed ROE 8.9%3 10.75% 1 A djus ted to inc lude pos t test-year plant in service through 06/30/2020 2 Rate Base excludes $215M approved through Joint Resolution in C ase No. E -01345A-19-0236. 3 RO E adjusted to reflect ROE approved through Joint Resolution in C ase No. E -01345A-19-0236. Rate base $ in billions, rounded $9.82 $9.92 $12.5 $1.91 $2.01 $2.7 2021 2022 2023 2024 2025 $11.9 Projected 5-7% Annual FERC ACC $11.7 $15.2 Third Quarter 2023 1 Derived from A PS annual update of formula transmission service rates. 2 Represents unadjusted ACC jurisdictional rate base consistent with regulatory filings.

Our goal continues to be declining O&M (as adjusted) per MWh 8 O&M (as adjusted) per MWh Total O&M (as adjusted)1 2022: $892M 2023: $915M-$935M 1 O&M amounts, as adjusted, exclude RES/DSM amounts of $95M in 2022 and $120M-$130M in 2023. Planned outage amounts included in O&M are $43M in 2022 and a projected $45M-$55M in 2023. For reconciliation, see slide 30. Third Quarter 2023 ~$30/MWh 2022

Forecasted sources of capital to fund investments from 2022-2024 No plans to issue equity before end of next rate case 9 Approx. $3 billion Approx. $1.4 billion $5.1 billion APS Debt2 PNW Debt2 Cash from Operations1 Approx. $300 million $400-$500 million 1 Cash from operations i s net of shareholder dividends. 2 APS and PNW debt issuance is net of maturities. Third Quarter 2023 Total Capital Investment PNW Equity/ Alternatives

Strong balance sheet with manageable long-term debt maturity profile 10 $M PNW Long-Term DebtAPS Long-Term Debt $0 $200 $400 $600 $800 $1,000 $1,200 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 2049 As of September 30, 2023 Third Quarter 2023

APPENDIX

Arizona remains among the fastest growing states in the U.S. 12 Consistent Residential Growth Past Five Years Strong 2.5% Sales CAGR Past Three Years 0.6% 0.8% 4.2% 2.4% 1.0%-3.0% 0% 1% 2% 3% 4% 5% 6% '19 '20 '21 '22 '23E Total Sales Growth2,3 2Weather-normalized 32019-2021 as reported in PNW Statistical Reports Third Quarter 2023 1.9% 2.1% 2.3% 2.4% 2.2% 1.5%-2.5% 0% 1% 2% 3% '18 '19 '20 '21 '22 '23E APS Residential Growth Natn'l Avg. - Residential Residential Customer Growth1 1National average from 2022 Itron Annual Energy Survey Report

Best-in-class service territory supports high tech growth and economic development 13 Our Approach: Focus on Four Main Areas Supports Influx of Manufacturing and Distribution – Examples • Business attraction and expansion • Community development • Entrepreneurial support • Infrastructure support • Taiwan Semiconductor Increased investment from $12B to $40B factory • Proctor & Gamble $500M capital investment in manufacturing facility • Jacuzzi $30M investment in 143k sq ft facility • Rehrig Pacific Company $80M investment in manufacturing facility • Air Products & Chemicals $160M investment in manufacturing facility • KORE Power $850M DOE loan to fund 1.3M sq ft facility Third Quarter 2023

A clear plan for clean energy transition 14 Progress Towards Meeting Clean Energy Commitment Pathway 2005 2019 2030 2050 Since 2020, have contracted over 4,500 MW of clean energy and storage to be in service for APS customers by end of 2025 Successfully installed 201 MW of APS owned batteries at our AZ Sun sites and 150 MW of solar at the Agave Solar Facility Charted course for healthy mix of APS-owned and third party- owned assets, to be continued through future planned RFPs 24% 50% 65% 100% Third Quarter 2023

Clean Energy Commitment – Over 4,500MW in development since 2020 Third Quarter 202315 Robust, Diverse Procurement Activity Energy Storage • 201 MW APS owned resources to retrofit entire fleet of AZ Sun facilities − Service began in 2023 • 1,842 MW under long-term PPAs • All resources to be in service between 2022 and 2025 Solar • 150 MW APS owned Agave Solar Facility; service began in 2023 • 1,471 MW under long-term PPAs • Resources in service or will be in-service no later than 2025 Wind • 654 MW under three long-term PPAs • Resources in service or will be in-service 2023 and 2024 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

2023 Planned Outage schedule Third Quarter 202316 Q2 Q4 Plant Unit Duration in Days Plant Unit Estimated Duration in Days Palo Verde 2 34 Palo Verde 1 35 Coal, Nuclear and Large Gas Planned Outages

2024 Planned Outage schedule Third Quarter 202317 Coal, Nuclear and Large Gas Planned Outages Q2 Plant Unit Estimated Duration in Days West Phoenix CC5 18 Palo Verde 3 35 Q1 Plant Unit Estimated Duration in Days Redhawk CC1 66 West Phoenix CC5 71 Q4 Plant Unit Estimated Duration in Days Palo Verde 2 35 Four Corners 5 66

$15 ($17) $67 Q1 Q2 Q3 Q4 Gross margin effects of weather Third Quarter 202318 Variances vs. Normal$ in millions pretax 2023 $65 Million All periods recalculated to current 10-year rolling average (2012 – 2021). Numbers may not foot due to rounding.

Renewable Energy & Demand Side Management expenses1 Third Quarter 202319 $10 $4 $12 $11 $15 $9 $16 $13 $16 $18 $11 $18 $21 $20 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Demand Side Management Renewable Energy 2022 $95 Million 1Renewable Energy and Demand Side Management expenses are substantially offset by adjustment mechanisms. 2023 $99 Million Numbers may not foot due to rounding.

Residential PV applications1 Third Quarter 202320 1Monthly data equals applications received minus cancelled applications. As of September 30, 2023 approximately 171,276 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling approximately 1,508 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 2020 Applications 2021 Applications 2022 Applications 2023 Applications 139 169 200 171 2020 2021 2022 2023

Credit Ratings Summary 21 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 October 27, 2023. Third Quarter 2023

2022 APS Rate Case – Updated Positions Third Quarter 202322 Key Financials Test year ended June 30, 2022 ACC Rate Base - Adjusted $10.4 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

2022 APS Rate Case – Updated Positions1 • Eliminate the Environmental Improvement Surcharge and collect costs through base rates • Maintain the Lost Fixed Cost Recovery Mechanism and Demand Side Management Adjustor Charge as separate mechanisms • Adopt a System Reliability Benefit recovery mechanism and maintain REAC in its current state • Modify the performance incentive in the Demand Side Management Adjustor Charge • Increase the Power Supply Adjustor Annual Cap from $0.004/kWh to $0.006/kWh 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 202323 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 New Customer Program Proposals

2022 APS Rate Case – Updated Positions1 24 Overview of Rate Increase Rebuttal Request ($ in Millions) Key Components1 • Initial Application Filed October 28, 2022; Rebuttal Filed July 12, 2023; Rejoinder filed August 4, 2023 • APS expects rates to become effective in Q1 2024 • Docket Number: E-01345A-22-0144 • Additional details, including filing, can be found at http://www.pinnaclewest.com/ratecase Additional Details Rate Base Growth $130 Revenue Impact of 12 Months Post Test Year Plant and Four Corners ELG 114 Weighted Average Cost of Capital of 7.17% 78 0.5% Fair Value Increment 34 New Customer Programs, Coal Community Transition and Other 21 Total Revenue Request $378 Customer Net Base Rate Impact on Day 1 11.2% 1Numbers may not foot due to rounding. Third Quarter 2023

2022 APS Rate Case - Testimony Summary11 25 1As of August 10, 2023. Numbers may not foot due to rounding. 2Alternatively, RUCO recommends a ROE of 8.7% if the Commission imputes a hypothetical capital structure with 46% equity layer. ACC Staff Surrebuttal Testimony RUCO Surrebuttal Testimony APS Rejoinder Testimony Return on Equity 9.68% 8.2%2 10.25% Fair Value Increment 0.50% 0.0% 0.50% Post Test-Year Plant 12 months + Four Corners ELG 6 months 12 months + Four Corners ELG New Capital Tracking Mechanism Not supported as proposed Did not address SRB All-Source Capital Recovery Mechanism (System Reliability Benefit or SRB) Existing Adjustors • Maintain LFCR and DSM as separate adjustors • Eliminate LFCR; increase DSM recovery through base rates • Keep current suite of adjustors with minor changes • Maintain LFCR and DSM as separate adjustors Additional items • Opposed Pension update • 50% D&O • 50% Incentive Comp • 50% D&O • 25% Incentive Comp • Updated Pension expense • 50% D&O • 50% Incentive Comp Total Revenue Requirement Increase $281.9M $84.9M $377.7M Customer Net Base Rate Impact on Day 1 8.4% 2.5% 11.2%

26 Application Filed October 28, 2022 Staff/Intervenor Direct Testimony Due June 5, 2023 Staff/Intervenor Direct Testimony (Rate Design) Due June 15, 2023 APS Rebuttal Testimony Due July 12, 2023 Staff/Intervenor Surrebuttal Testimony Due July 26, 2023 APS Rejoinder Testimony Due August 4, 2023 Pre-Hearing Conference August 7, 2023 Hearing Commences August 10, 2023 Hearing Concluded October 3, 2023 Briefs Due November 6 & 21, 2023 Arizona Public Service Company Docket # E-01345A-22-0144 2022 APS Rate Case Procedural Schedule Third Quarter 2023

Regulatory 2023 key dates1 Third Quarter 202327 ACC Key Dates / Docket # Q1 Q2 Q3 Q4 2022 Rate Case: E-01345A-22-0144 Hearing commenced August 10 Hearing concluded October 3 Power Supply Adjustor (PSA) E-01345A-19-0236: Effective March 1 2024 PSA Rate to be filed Nov 30 Transmission Cost Adjustor E-01345A-19-0236: Filed May 15; effective June 1 Environmental Improvement Surcharge E-01345A-19-0236: Filed Feb. 1 Effective April 1 Lost Fixed Cost Recovery E-01345A-23-0228: Filed July 31 Resource Planning and Procurement: E-99999A-22-0046 2023 IRP filed November 1 2023 DSM/EE Implementation Plan E-01345A-22-0066: 2024 Plan to be filed November 30 2023 RES Implementation Plan E-01345A-22-0181: 2024 Plan filed June 30 Resource Comparison Proxy E-01345A-23-0110: Filed May 1 Approved August 25 Effective Sep 1 Battery Storage PPAs through the PSA (New dockets): 4 Applications approved 5 Applications approved 1Dates are estimated and subject to change.

Pension & Other Post Retirement Benefits (“OPEB”) 28 Third Quarter 2023 104% 107% 106% YE 2020 YE 2021 YE 2022 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. 2 +/-/= represent expected comparative year-over-year impact of each driver on benefit expense. 3 Net impact of higher expected return percentage applied to smaller asset va lue year-over-year. . Components of Benefit Cost 2023E2 Service Cost + Non-Service Costs/(Credit): Interest Cost - Expected Return on Assets3 - Amortization of Prior Service Costs = Amortization of Actuarial Losses/(Gains) - Discount Rate: Pension 2.92% 5.56% Expected Long-Term Return on Plan Assets: Pension 5.00% 6.70% Pension Expense Assumptions 2022 2023E Total Benefit Expense/(Income) $(61.5) $(16.0)

Components and Key Drivers of Benefit Costs1 Third Quarter 202329 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.

Non-GAAP Measure Reconciliation Third Quarter 202330 2022 Actuals4 2023 Guidance4 Operating revenues1 $4.32 billion $4.71 - $4.79 billion Fuel and purchased power expenses1 $1.63 billion $1.86 - $1.91 billion Gross Margin $2.69 billion $2.84 - $2.89 billion Adjustments: Renewable energy and demand side management programs2 $100 million $120 - $130 million Adjusted gross margin $2.59 billion $2.72 - $2.77 billion Operations and maintenance1,3 $987 million $1.04 - $1.06 billion Adjustments: Renewable energy and demand side management programs2 $95 million $120 - $130 million Adjusted operations and maintenance $892 million $915 - $935 million 1Line i tems from Consolidated Statements of Income. 2Includes $5M for CCT (Coal Community Transition) in 2022 and $3M in 2023 which is recovered through REAC (Renewable Energy Ad justment Charge) 3O&M per MWh was $33/MWh in 2022. 4Numbers may not foot due to rounding.

Consolidated statistics Third Quarter 202331 Numbers may not foot due to rounding. 3 Months Ended June 30 3 Months Ended September 30, 9 Months Ended September 30, 2023 2022 Incr (Decr) 2023 2022 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential $ 883 $ 743 $ 140 $ 1,835 $ 1,648 $ 187 Business 649 548 101 1,572 1,370 202 Total Retail 1,533 1,291 242 3,407 3,018 389 Sales for Resale (Wholesale) 58 140 (82) 181 198 (18) Transmission for Others 43 36 7 108 91 17 Other Miscellaneous Services 4 3 1 8 7 1 Total Operating Revenues $ 1,638 $ 1,470 $ 168 $ 3,704 $ 3,315 $ 389 ELECTRIC SALES (GWH) Retail Residential 5,778 5,389 389 12,030 11,824 206 Business 5,024 4,768 256 12,505 12,101 404 Total Retail Sales 10,802 10,157 645 24,535 23,925 610 Sales for Resale (Wholesale) 1,491 1,376 115 3,492 2,603 889 Total Electric Sales 12,292 11,532 760 28,027 26,528 1,499 RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 5,209 5,309 (100) 11,457 11,558 (101) Business 4,850 4,748 101 12,369 12,042 327 Total Retail Sales 10,059 10,058 2 23,826 23,600 226 Retail sales (GWH) (% over prior year) 0.0% 1.3% 1.0% 2.7% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,227,556 1,202,870 24,685 1,224,260 1,199,245 25,015 Business 143,388 141,619 1,769 142,750 141,169 1,581 Total Retail 1,370,944 1,344,489 26,454 1,367,010 1,340,414 26,596 Wholesale Customers 57 56 1 56 54 2 Total Customers 1,371,001 1,344,545 26,455 1,367,067 1,340,469 26,598 Total Customer Growth (% over prior year) 2.0% 2.0% 2.0% 2.1% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 4,244 4,414 (170) 9,359 9,638 (279) Business 33,823 33,529 294 86,647 85,305 1,343

Consolidated statistics Third Quarter 202332 Numbers may not foot due to rounding. 3 Months Ended June 30 3 Months Ended September 30, 9 Months Ended September 30, 2023 2022 Incr (Decr) 2023 2022 I cr (Decr) ENERGY SOURCES (GWH) Generation Production Nuclear 2,524 2,532 (8) 7,022 7,121 (99) Coal 2,127 2,591 (464) 5,325 6,252 (927) Gas, Oil and Other 3,072 2,814 258 6,800 6,451 349 Renewables 281 155 126 526 452 74 Total Generation Production 8,004 8,092 (88) 19,673 20,276 (603) Purchased Power Conventional 3,313 2,389 924 5,841 4,294 1,548 Resales 828 1,091 (263) 1,224 1,281 (58) Renewables 732 493 238 2,147 1,755 392 Total Purchased Power 4,873 3,973 900 9,212 7,330 1,882 Total Energy Sources 12,877 12,066 811 28,885 27,606 1,279 POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 100% 100% (0)% 94% 95% (1)% Coal 71% 86% (15)% 60% 70% (10)% Gas, Oil and Other 38% 36% 3% 29% 27% 1% Solar 56% 31% 25% 35% 30% 5% System Average 57% 58% (1)% 47% 49% (2)% 3 Months Ended September 30, 9 Months Ended September 30, 2023 2022 Incr (Decr) 2023 2022 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days 1,622 1,266 356 2,046 1,836 210 Heating Degree-Days N/A N/A #VALUE! 700 454 246 Average Humidity 23% 35% (12)% 21% 28% (7)% 10-Year Averages (2012 - 2021) Cooling Degree-Days 1,229 1,229 - 1,753 1,753 - Heating Degree-Days N/A N/A 437 437 - Average Humidity 32% 32% 0% 26% 26% 0%