Slides
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Third Quarter 2026 Earnings October 28, 2026
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Cautionary Note Regarding Forward -Looking Statements 2 This presentation contains forward-looking statements. Words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, including statements reflecting future results or guidance and statements of outlook are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: changes in economic conditions, electric market demand and demographic patterns in AEP’s service territory, the economic impact of increased global conflicts and trade tensions, and the adoption or expansion of economic sanctions, tariffs, trade restrictions or changes in trade policy, inflationary or deflationary interest rate trends, new modified, repealed or suspended federal, state or local legislation, regulations, policies or executive actions that alter the regulatory framework; delay or prevent approvals or permits; affect approved or planned investments; or prevent timely recovery of costs and investments, volatility and instability in financial markets precipitated by disruptive events, including fiscal and monetary policy or uncertainty in the banking industry; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt, the availability and cost of funds to finance working capital and capital needs, particularly (i) if expected sources of capital, such as proceeds from the sale of tax credits and anticipated securitizations do not materialize or do not materialize at the level anticipated, and (ii) during periods when the time lag between incurring costs and recovery is long and the costs are material, changing demand for electricity including large load contractual commitments, the risks and uncertainties associated with wildfires, including damages caused by wildfires, the extent of each Registrant’sliability in connection with wildfires, investigations and outcomes associated with legal proceedings, demand or similar actions, inability to recover wildfire costs through insurance or through rates and the impact on financial condition and the reputation of each Registrant, the impact of extreme weather conditions, natural disasters and catastrophic events such as storms, wildfires and drought conditions that pose significant risks including potential litigation and the inability to recover significant damages and restoration costs incurred, limitations or restrictions on the amounts and types of insurance available to cover losses that might arise in connection with natural disasters, wildfires or operations, the cost of fuel and its transportation, the creditworthiness and performance of parties who supply and transport fuel and the cost of storing and disposing of used fuel, including coal ash and spent nuclear fuel, the availability of fuel and necessary generation capacity and performance of generation plants, the ability to recover fuel and other energy costs through regulated or competitive electric rates, the ability to plan for, develop, construct, acquire, or integrate a broad range of generation and energy storage resources, as well as related transmission and distribution infrastructure, including obtaining necessary regulatory approvals, permits, and incentives for which the timing is dependent upon the priorities, requirements, processes and determinations of the local policy and regulatory authorities; complying with cost caps and other regulatory or contractual requirements; and recovering associated costs and earning an appropriate return while meeting reliability, affordability, environmental, and customer-service obligations, the disruption of AEP’s business operations due to impacts of economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers caused by, natural disasters or other events, construction and development risks affecting completion of the current or future capital investment plans, including labor, material, equipment or parts shortages and delays; and limited availability and extended lead times for critical equipment, including large power transformers and bridging power solutions, the impact of prolonged or recurring U.S. federal government shutdowns on AEP’s operations, regulatory approvals, and financial performance including potential volatility in the capital markets which may interrupt our access to capital, new legislation, litigation or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, evolving environmental standards, energy commodity trading and new or modified requirements related to emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets, the impact of tax legislation or associated Department of Treasury guidance, including potential changes to existing tax incentives, on capital plans, results of operations, financial condition, cash flows or credit ratings, the risks before, during and after generation of electricity associated with the fuels used or the byproducts and wastes of such fuels, including coal ash and spent nuclear fuel, timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance, resolution of litigation or regulatory proceedings or investigation, the ability to efficiently manage and recover operation, maintenance and development project costs, prices and demand for power generated and sold in wholesale markets, changes in technology, including new, developing, alternative or distributed sources of generation, the ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives, volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas, the impact of changing expectations and demands of customers, regulators, investors and stakeholders, including development, adoption and use of AI by us, our customers, and our third party vendors and evolving expectations related to sustainability, customer affordability concerns may impact regulatory recovery outcomes and future rate design, changes in utility regulation, policies, methodologies for evaluating and approving load interconnection, and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP and the impacts of potential market changes or our participation within those regional transmission organizations, changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market, actions of rating agencies, including changes in ratings impacting the cost of debt, the impact of geopolitical developments on global energy markets including volatility in fuel supply and pricing, power-generation economics and customer demand patterns, the impact of volatility in the capital markets on the value of the investments held by the pension, OPEB and nuclear decommissioning trust fund and a captive insurance entity and the impact of such volatility on future funding requirements, accounting standards periodically issued by accounting standard-setting bodies, the ability to successfully defend against cybersecurity threats, other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, labor strikes impacting material supply chains, global information technology disruptions and other catastrophic events, the ability to attract and retain requisite work force and key personnel, including senior management. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement.
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Non-GAAP Financial Measures AEP reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). AEP supplements its reporting of financial information with certain non-GAAP financial measures, including operating earnings (non-GAAP), operating EPS (non-GAAP), adjusted equity (non-GAAP) and FFO to total debt (non-GAAP). Operating earnings exclude certain gains and losses and other specified items, including mark-to-market adjustments from commodity hedging activities and other items as set forth in the reconciliation in the Appendix. Adjusted equity is adjusted for Midwest Transmission Holdings Noncontrolling Interest Transaction. FFO to total debt is adjusted for capital and operating leases, pension, capitalized interest, adjustments related to hybrid debt, deferred fuel, minority interest and changes in working capital. Operating earnings could differ from GAAP earnings for matters such as impairments, divestitures, or changes in accounting principles. AEP management is not able to forecast if any of these items will occur or any amounts that may be reported for future periods. Therefore, AEP is not able to provide a corresponding GAAP equivalent for earnings guidance. Reflecting special items recorded through the third quarter of 2026, the estimated earnings per share on a GAAP basis would be $6.11 to $6.41 per share. This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of AEP’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this informationis among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. AEP has provided these non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the Appendix and supplemental schedules to this presentation. Throughout this presentation, we use the terms operating earnings, operating EPS, adjusted equity and FFO to total debt. The Appendix and supplemental schedules accessible on our website contain reconciliations of these terms to the most comparable GAAP measure. 3
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Key Themes and Updated Strategic Outlook B i l l F e h r m a n C h a i r m a n , P r e s i d e n t a n d C E O
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Executive Summary 5 Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Based on 2026 original guidance midpoint. 2. Projected fixed cost offsets for residential customers over the life of the signed Electric Service Agreements in the VIUs. Updated Strategic Growth Outlook • Launching $100B five-year capital plan, driven by AEP’s differentiated growth platform in transmission and generation • Announcing 2027 and 2028 operating earnings guidance ranges of $6.75-$7.05 and $7.40-$7.70 per share, respectively • Introducing a new expected annual operating EPS growth rate of 9%-11% and 10%+ CAGR through 20311 • Supporting customer affordability largely through AEP’s projected ability to attract new large loads with up to $21B 2 of estimated fixed cost offsets, increased from $16B, for residential customers in the vertically integrated utilities (VIUs) Third Quarter Results • Reporting third quarter 2026 operating EPS of $2.23 and YTD 2026 operating EPS of $5.24 • Guiding full-year results to be at or above the high end of the 2026 operating EPS range of $6.25-$6.55
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AEP’s Superior Growth Platform AEP’s size, diversification, and broad participation across the electric utility value chain provide multiple pathways to deliver sustained long-term growth. ~40k Transmission Line Miles ~253k Distribution Line Miles ~34 GW of Owned and Contracted Capacity ~5.6M Customers 6 Forecasted Investment Highlights Differentiated Investment Thesis Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Management’s load growth expectations are based on underlying trends. Commercial load, driven by growth in energy intensive subsectors such as AI driven data center demand, is anticipated to be the largest component of retail load growth. Forecasted data center demand growth is supported by existing and future customer financial agreements, which are subject to certain terms and conditions. 13%+ Rate Base CAGR Through 2031 10%+ Operating EPS CAGR Through 2031 and 10% EPS CAGR Through 2033 $100B Capital Plan 2027-2031 12%-14% Annual Expected TSR $21B Fixed Cost Offsets for Residential Customers 9%-11% Annual Operating EPS Growth Rate Through 2031 84 GW Contracted Load Through 20311 $162B Regulated Rate Base 2031 14%-15% Targeted FFO/ Debt Range
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Scale, Diversification and Constructive Markets AEP’s 11-state footprint provides a differentiated advantage through its scale, favorable economic and business fundamentals, and constructive regulatory jurisdictions. 7 AEP Service Territory 6 States Served by AEP Ranked Among CNBC's Top 10 States for Business in 20262 >25% of U.S. GDP Generated by States Served by AEP’s Regulated Utilities in 20251 90% Timely Recovery Planned Utility Capital to be Recovered Through Reduced Lag Mechanisms 84 GW Contracted Load Expected by 2031 Backed by Electric Service Agreements (ESA) and Letters of Agreement (LOA) 1. 2025 GDP data by state from Bureau of Economic Analysis. 2. Ranking from CNBC’s “America’s Top States for Business 2026” article published on 7/9/2026.
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Largest Transmission Network AEP owns and operates the nation’s largest transmission network, enabling the company to provide unique customer solutions and drive significant expected growth. Nation’s largest transmission owner with ~40,000 miles of lines, representing more than 50% of AEP’s earnings1 Largest 765 kV transmission system with plans to nearly triple the number of miles over the next five years AEP owns and operates ~90% of the nation’s 765 kV transmission lines across six states Strategic partnership with Quanta Services accelerating project development and critical equipment manufacturing Projects in active development and construction across four markets, including PJM, ERCOT, SPP, and MISO 8 Transmission Assets in Operation 765 kV 500 kV, 345 kV and 138 kV Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Expected 2027 operating earnings; includes AEP Transmission Holdco and transmission investments in AEP operating companies.
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Driving Customer Affordability AEP’s ability to secure new large loads translates directly into customer affordability benefits. Large Load Growth Higher volume in C&I classes as a percentage of total sales Re-Allocated Fixed Costs Higher percentage of fixed costs shifted from residential to large load customers Enhanced Affordability Reduced rate impacts for existing residential customers 9 $21B of expected fixed cost offsets for residential customers from signed ESAs in VIUs Base rate reductions implemented in Ohio and proposed in Indiana Data center tariffs with significant protections for existing customers secured in six states New structures being pursued in which data center customers pay for full cost of upgrades $5B in DOE loans and $625M in DOE grants secured, estimated $1.6B in interest savings AEP Customer Affordability Highlights $21B Expected Fixed Cost Offsets
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A Leading Value Proposition AEP’s scale, diversification, presence in high-growth markets, and disciplined execution position the company to deliver differential value for our customers and shareholders. 10 AEP’s differentiated growth platform expected to drive estimated rate base to $162B by 2031 Significant scale as one of the nation’s largest utility holding companies Diversified 11-state platform Operating in constructive, high-growth markets Nation’s largest transmission network Differentiated ability to drive meaningful affordability benefits Enhanced relationships with state regulators and customers Established partnerships with major suppliers and craft labor firms Strong balance sheet facilitating accretive growth Capital Plan Increase $78B $100B Prior 2026-2030 Capital Plan New 2027-2031 Capital Plan ~30% Increase
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11 • AEP ANALYST DAY 2022 Third Quarter 2026 Results and Financial Growth Outlook T r e v o r M i h a l i k C F O
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$1.80 $2.23 $0.25 $0.04 $0.03 $0.10 $0.01 2025 Actual VIUs T&Ds AEP Transmission HoldCo Generation & Marketing Corporate & Other 2026 Actual 2026 Actual $1.32 $0.52 $0.40 $0.19 $(0.20) $2.23 Q3 2026 Operating Earnings Drivers AEP’s strong third quarter performance reflects disciplined execution, constructive regulatory outcomes, growing customer demand, and continued investment across the business. 12 Rate Changes $0.31 Weather $0.15 Normalized Sales $0.07 Other Taxes $(0.01) O&M $(0.03) Depreciation $(0.05) Net Interest $(0.06) Reliability Spend $(0.07) Other $(0.06) Rate Changes $0.07 Transmission Revenue $0.06 Weather $0.03 Net Interest $(0.01) O&M $(0.02) Other Taxes $(0.02) Reliability Spend $(0.04) Other $(0.03) Wholesale and Other $0.09 Retail $0.01 Income Taxes $0.12 Net Interest $(0.04) O&M $(0.05) Other $(0.02) Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Investment Growth $0.03
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$4.78 $5.24$0.46 $0.14 ($0.03) $0.11 ($0.22) 2025 Actual VIUs T&Ds AEP Transmission HoldCo Generation & Marketing Corporate & Other 2026 Actual 2026 Actual $2.74 $1.40 $1.20 $0.52 $(0.62) $5.24 YTD 2026 Operating Earnings Drivers 13 Rate Change $0.70 Normalized Sales $0.24 Transmission Revenue $0.13 Weather $0.11 O&M $(0.09) Depreciation $(0.18) Net Interest $(0.20) Reliability Spend $(0.31) Other $0.06 Transmission Revenue $0.19 Rate Changes $0.16 Normalized Sales $0.05 Weather $(0.03) Net Interest $(0.03) O&M $(0.04) Other Taxes $(0.04) Reliability Spend $(0.09) Other $(0.03) Wholesale and Other $0.19 Retail $(0.08) Net Interest $(0.08) O&M $(0.09) Other $(0.05) Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. AEP’s YTD performance provides confidence in delivering full-year 2026 operating earnings at or above the high end of our $6.25 to $6.55 per share guidance range. O&M $(0.01) Other $(0.02)
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Long-term EPS Growth 14 Projecting an expected annual operating EPS growth rate of 9-11% with a CAGR of 10%+ through 2031. Operating EPS Growth Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 9%-11% Annual operating EPS growth rate through 2031 10%+ Operating EPS CAGR through 2031 based on original 2026 guidance midpoint 10% Operating EPS CAGR through 2033 based on original 2026 guidance midpoint 2026 2027 2028 2031 $6.30 $6.75-$7.05 $7.40-$7.70 ~9.5% Annual Growth ~9.5% Annual Growth Original Guidance Midpoint 10%+ CAGR Through 2031
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2027-2031 Capital Plan and Rate Base Growth AEP’s updated five-year capital plan supports a robust expected rate base CAGR of 13%+ through 2031. Capital Plan by Year ($B) Rate Base Growth ($B) Transmission Regulated Generation Distribution AEP Infrastructure $17 $20 $24 $27 $31 $34 $26 $30 $34 $38 $42 $45 $44 $52 $63 $73 $78 $83 $87 $102 $121 $138 $151 $162 2026E 2027E 2028E 2029E 2030E 2031E 13%+ Rate Base CAGR 15 $6 $8 $8 $8 $7 $6 $9 $8 $4 $5 $4 $5 $4 $5 $4 $3 $1 $1 $1 $1 $1 $1 $20 $24 $21 $18 $17 2027 2028 2029 2030 2031 Corporate and Other Transmission Holdco/JVs T&D VIUs
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$19 $18 $20 $8 $4 $4 $22 $51 $100B Five-Year Capital Plan 37% Transmission 36% Generation 22% Distribution 5% Corp & Other Diversified Capital Plan with Strong Recovery AEP's large, diversified capital plan and timely recovery mechanisms support long-term earnings and cash flow visibility. 16 Timely Recovery of Utility Capital Formula Rates, Riders and Trackers Forward Test Year Historic Test Period 2027-2031 Capital Plan ($B) 1. Includes AEP and operating companies. Transmission Transmission HoldCo Gas Generation Regulated Renewables AEP Infrastructure Other Generation Distribution Corporate and Other 81% 7% 12% ~90% Utility Capital to be Recovered Via Reduced Lag Mechanisms
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2027-2031 Capital Forecast by Subsidiary Significant investments in transmission and generation expected to drive robust rate base growth through 2031. 17 ($B, excludes AFUDC) 2027E 2028E 2029E 2030E 2031E Total AEP Transmission Holdco $3.0 $3.9 $3.5 $4.1 $3.5 $18.0 Appalachian Power Company1 $1.7 $2.3 $4.1 $4.2 $4.9 $17.2 AEP Texas Inc. $3.1 $3.9 $3.5 $3.4 $3.0 $16.9 Public Service Company of Oklahoma $4.3 $4.6 $2.3 $1.4 $0.9 $13.5 Indiana Michigan Power Company $1.8 $4.4 $3.6 $1.2 $0.9 $11.9 Southwestern Electric Power Company $1.5 $1.4 $1.9 $1.6 $1.6 $8.0 Ohio Power Company $1.2 $1.3 $1.4 $1.4 $1.4 $6.7 AEP Infrastructure $2.6 $1.4 $0.1 $0.1 $0.1 $4.3 Kentucky Power Company $0.3 $0.3 $0.3 $0.3 $0.4 $1.6 Other2 $0.9 $0.4 $0.3 $0.4 $0.3 $2.3 Total Capital $20.4 $23.9 $21.0 $18.1 $17.0 $100.4 50% 26% 10% 4% 4% 6% Transmission $37B AEP Texas SWEPCO APCo1 Ohio Power Other (includes PSO, I&M, KPCo and KGPCo) AEP Transmission Holdco 33% 27% 23% 12% 5% Generation $36B APCo1 PSO I&M Other (includes SWEPCO, KPCo and AEG) AEP Infrastructure 29% 22%15% 11% 11% 10% 2% Distribution $22B AEP Texas Ohio Power APCo1 PSO I&M SWEPCO Other (includes KPCo and KGPCo) Note: Capital plans are continuously optimized which may result in redeployment between timing, functions and companies. 1. Includes Wheeling Power Company. 2. Excludes approximately $3B allocated to the operating companies.
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69 GW 84 GW 11 GW 2 GW 1 GW 1 GW Previous Contracted Load Ohio Power ESAs (incl. Piketon) APCo ESAs PSO ESAs Other Current Contracted Load Contracted Load Growth 18 AEP’s contracted load increased from 69 GW to 84 GW, driven by additional firm take-or-pay ESAs. In total, 35 GW of signed ESAs are facilitating significant transmission and generation growth in the new capital plan. Drivers of Contracted Load Since Q2 2026 Incremental Contracted Load Through 2031 ~15 GW ESAs Signed Since Q2 2026 Earnings Call ~35 GW Incremental Load Under Firm Take-or-Pay ESAs 73% ESAs in SPP Related to 7 GW of Total Contracted Load in SPP Through 2031 99% ESAs in PJM Related to 31 GW of Total Contracted Load in PJM Through 2031 ESAs – PJM and SPP LOAs – PJM and SPP LOAs – ERCOT 84 GW Contracted Load by 2031 35 GW 3 GW 46 GW
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Financing Plan AEP’s updated financial plan is supported by robust operating cash flows and a disciplined financing approach, resulting in incremental equity of ~24% for the $22B of additional capital while targeting 14% to 15% FFO-debt in the forecast period. 19 Financing Plan ($B) 2027E - 2028E 2029E - 2031E Total Cash from Operations $18.0 $36.9 $54.9 Less: Capital Expenditure (44.3) (56.1) (100.4) Less Common Dividends1 (4.7) (8.1) (12.8) Required Capital (31.0) (27.3) (58.3) Net Debt Capital Raised2 21.0 23.4 44.4 Settlement of Forwards from Prior Equity 4.7 - 4.7 Previous ATM Program3 1.0 2.0 3.0 Incremental ATM Program 1.4 1.3 2.7 Incremental Marketed Growth Equity 2.5 - 2.5 Dividend Reinvestment Plan 0.4 0.6 1.0 Actual cash flows will vary by company and jurisdictions based on regulatory outcomes. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Dividends per share remain constant until approved by Board of Directors. Dividends evaluated by Board of Directors each quarter and may be adjusted based on capital allocation priorities and other strategic considerations. 2. Could include equity-like instruments. 3. Executed approximately $1B of ATM equity issuance YTD 2026. 55% Capital Plan Funded by Operating Cash Flow $22B Incremental Capital Versus Prior 2026-2030 Plan $5.2B Incremental Growth Equity Versus Prior 2026-2030 Plan 24% Equity to Fund $22B of Incremental Capital
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Conclusion 20Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Forecasted Investment Highlights Projecting to be at or above high end of the full-year 2026 operating EPS guidance range of $6.25-$6.55 Updated $100B five-year capital plan through 2031, supported by significant growth in transmission and generation Updated expected annual operating EPS growth rate of 9%-11% and expected 10%+ CAGR through 2031 Supporting affordability benefits with up to $21B of expected fixed cost offsets for existing residential customers from fully executed ESAs in the VIUs Key Takeaways 13%+ Rate Base CAGR Through 2031 10%+ Operating EPS CAGR Through 2031 and 10% EPS CAGR Through 2033 $100B Capital Plan 2027-2031 12%-14% Annual Expected TSR $21B Fixed Cost Offsets for Residential Customers 9%-11% Annual Operating EPS Growth Rate Through 2031 84 GW Contracted Load Through 2031 $162B Regulated Rate Base 2031 14%-15% Targeted FFO/ Debt Range
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Appendix
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2027 Operating Earnings Guidance 22 2027E $3.48 $1.93 $1.72 $0.63 ($0.86) $6.90 $6.30 $6.90 $0.15 $0.23 $0.17 $0.26 ($0.21) 2026E VIUs T&Ds AEP Transmission HoldCo AEP Infrastructure Corporate & Other 2027E AEP’s 2027 operating earnings guidance is supported by multiple drivers, including: Note: Operating earnings, which could differ from earnings reported in accordance with GAAP, exclude certain gains and losses and other specified items that management believes are not indicative of AEP’s ongoing performance. AEP management is not able to forecast if any of these items will occur or any amounts that may be reported for future periods. Refer to “Non-GAAP Financial Measures”. Projecting ~9.5% year-over-year growth based on EPS guidance midpoints. ✓ Continued growth across regulated utility operations supported by constructive regulatory outcomes, robust customer demand and ongoing infrastructure investment ✓ Contributions from AEP Infrastructure, an asset-backed business supported by high- quality long-term contracts
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AEP Infrastructure Overview Going forward, we expect AEP Infrastructure to be largely focused on projects backed by high-quality, long- term contracts. 23 Contracted Infrastructure • Energy infrastructure projects supported by long-term agreements with high-quality counterparties, such as: ‒ Wyoming fuel cell project supported by 20-year PPA with Google and targeted to be in-service by year- end 2028; total estimated capital of ~$4B ‒ Substation project delivery, including designing, engineering, and constructing for third parties Generation • Operating generation assets, including OVEC, Longview and Wolf Hills Retail • Competitive supplier of electricity and natural gas to end-use customers Wholesale • Electric sales, purchase power agreement sourcing, congestion management, RTO services and portfolio optimization AEP Infrastructure | Primary Assets and Operations
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Transmission Growth Transmission Capital Plan ($B) 24 RTO Driven Transmission Projects System Reliability Investments Transmission for Individual Customers (incl. Piketon) $17 $11 $9 $37B Transmission Capital Plan (2027-2031) AEP’s leading transmission business is expected to continue to be a key growth driver in the updated five- year capital plan, with transmission rate base to nearly double by 2031. Transmission Rate Base Growth ($B) $17 $20 $24 $27 $31 $34 $20 $23 $26 $28 $32 $35 $37 $43 $50 $55 $63 $69 2026E 2027E 2028E 2029E 2030E 2031E 13%+ Rate Base CAGR Rate base of AEP Transmission Holdco Rate base of transmission investments in AEP operating companies
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Regulated Gas Generation Growth 25 AEP is advancing a significant gas-fired generation buildout program to meet growing load in the VIUs, leveraging the company’s secured turbine slots and strategic partnerships with blue-chip EPCs. Select Gas-Fired Generation Included in Capital Plan Company New Plants Equipment Target In Service Capacity 1 CT 2027 450 MW 3 CT, CCGT 2028 – 2030 3,100 MW 2 CCGT 2029-2030 2,400 MW 3 CCGT 2031 – 2032 3,100 MW Key Relationships
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Capital Recovery Mechanisms Through successful regulatory execution over the last two and a half years, AEP has significantly improved recovery of capital investments across its portfolio, further de-risking the $100B capital plan. 26 ✓ FERC formula rates that are cost-based with approved incentives ✓ HB 15 enables multi-year rate plan (MYRP) with forward looking test years; Ohio Power Company to file first MYRP in 2027 ✓ Rider recovery of distribution and transmission investment ✓ Unified Tracker Mechanism (UTM) enables qualifying utilities to apply for interim rate adjustments annually ✓ MYRP with forward-looking test years (IN) ✓ HB 1007 enables accelerated approval of natural gas- fired generation with deferred cost recovery (IN) ✓ Generation pre-approval filings support concurrent rider and CWIP recovery ✓ SB 998 allows deferral of 90% of distribution and general plant that goes in service between rate cases ✓ Ability to include forecasted distribution capital in rate cases (VA) ✓ Recovery of generation and transmission investments via rate adjustment clause (VA) ✓ Generation rider enables recovery of existing plant balances and new generation, including CWIP ✓ Rider recovery of forecasted and actual transmission investment and actual generation investment (LA) ✓ Rider recovery of transmission, distribution, and generation investment (TX) ✓ Partially-forecasted rate case test years with 12 months of forecast pro forma adjustments allowed (AR)
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2027-2031 Load Growth Incremental contracted load of 84 GW by 2031 is backed by fully executed ESAs and LOAs. 27 2027E 2028E 2029E 2030E 2031E 17 GW 20 GW 22 GW 17 GW 8 GW Cumulative Contracted Load Additions (GW) Contract Breakdown Company Breakdown 10 23 38 45 46 6 12 17 25 31 1 2 4 6 7 17 37 59 76 84 2027E 2028E 2029E 2030E 2031E ERCOT PJM SPP GW by Year, Totaling 84 GW (2027-2031) 42% 54% 4% ESA Other LOA Texas LOA1 92% 8% Industry Breakdown Data Centers2 Industrials 55%27% 7% 5%4% AEP Texas (46 GW) Ohio Power (23 GW) PSO (6 GW) I&M (4 GW) APCo (3 GW) KPCo (1 GW) SWEPCO (1 GW) 1. Reflects the Batch Zero load that AEP Texas submitted in July 2026, which included 45 GW of projects for the 2027-2032 period. In this filing, 16 GW was classified as Base Load and 29 GW was classified as Studied Load. 2. Includes crypto customers. 1
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Current Rate Case Activity 28 Docket # PUR-2026-00044 Filing Date 5/29/2026 Requested Rate Base $2.3B Requested ROE 10.5% Cap Structure 50.2%D / 49.8%E Gross Revenue Increase $61M Test Year 12/31/2025 Settlement Summary1 Pending Commission Approval Settlement Filed 10/14/2026 Expected Effective Date March 2027 Expected Commission Order Q1 2027 ROE 9.8% Cap Structure 50.2%D / 49.8%E APCo – Virginia SWEPCO – TexasPSO Docket # 58819 Filing Date 10/14/2025 Requested Rate Base $2.4B Requested ROE 10.75% Cap Structure 48.02%D / 51.98%E Gross Revenue Increase5 $95M (Less $11M D&A) Net Revenue Increase $84M Test Year 3/31/2025 Settlement Summary Pending Commission Approval Settlement Filed 9/17/2026 Expected Effective Date March 2026 Expected Commission Order Q4 2026 ROE 9.53% Cap Structure 48.02%D / 51.98%E Net Revenue Increase $47.5M I&M – Indiana Docket # 46454 Filing Date 8/26/2026 Requested Rate Base $7.6B Requested ROE 10.1% Cap Structure 48.8%D / 51.2%E Net Revenue Decrease2 $59M Test Year 12/31/2027 Procedural Schedule Intervenor Testimony 12/4/2026 Rebuttal Testimony 1/11/2027 Hearing 2/22/2027 Expected Effective Date July 2027 Expected Commission Order June 2027 Docket # PUD 2025-000075 Filing Date 1/2/2026 Requested Rate Base $7.2B Requested ROE 10.5% Cap Structure 50.15%D / 49.85%E Gross Revenue Increase3 $299M (Less $118M D&A) Net Revenue Increase $181M Test Year 7/31/2025 Settlement Summary4 Pending Commission Approval Settlement Filed 6/26/2026 Expected Effective Date July 2026 Expected Commission Order Q4 2026 ROE 9.375% Cap Structure 50.15%D / 49.85%E Net Revenue Increase $149M Achieving positive regulatory outcomes to advance affordability, system reliability, resiliency and security. 1. Settlement migrates approximately $49M of vegetation management and ARO recovery from base rates to annual rider mechanisms with rider filings expected in early 2027, supporting more concurrent recovery. 2. Base rate case filing utilizes deferred regulatory liabilities to reduce customer rates, which is not earnings-related and directly supports affordability. The filing sets new authorized net operating income levels that support the company’s financial profile. The filing includes a proposed three-year multi-rate plan; amounts shown reflect Year 1. 3. Does not include $298M moving from rider recovery to base rates and production tax credits. 4. The settlement includes full tracking of the SPP transmission cost. 5. Does not include $69M moving from rider recovery to base rates.
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Regulated Earned Returns 29 9.6% 8.9% 7.4% 4.0% 11.7% 10.3%3 9.1% 8.5% 10.0% 2% 4% 6% 8% 10% 12% 14% I&M4 Ohio Power Company Transmission Holdco AEP TexasPSO4 APCo4SWEPCO4 KPCo 8.8% 2023 9.05% 2024 9.1% 2025 9.3%-9.5% 2026E 9.5% Historical and Projected Regulated ROE Trend 9.5% earned ROE1,2 as of twelve months ended 9/30/2026 9.5% Earned ROE1,2 Forecasted regulated ROE is expected to be 9.5% in 2030 and beyond, only 20 basis points from the blended authorized ROE of 9.7%. 2031E Note: Sphere size is based on each company’s relative equity balance. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Calculated based on non-GAAP operating earnings, not weather normalized. 2. Calculated based on adjusted average equity which excludes $1.79B of 13-month average paid-in-capital associated with the 2025 Midwest Transmission Holdings noncontrolling-interest transaction. 3. Excludes Rockport Unit 2. 4. Base rate cases pending/order recently received. 9.5% 2030E
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30 • AEP ANALYST DAY 2022 Supplemental Financial Information
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Third Quarter Liquidity and Credit Metrics 31 S&P Moody’s Fitch Rating / Outlook BBB / Stable Baa2 / Stable BBB / Stable Credit Metric FFO/Debt: 14.7% FFO/Debt: 14.8%1 FFO Leverage: 5.1x Targeted Range 14%-15% 5.0x-5.5x Downgrade Threshold 13% Sustained 5.8x Sustained Liquidity Summary 9/30/2026 ($M) Credit Metrics Trailing 12 Months as of 9/30/2026 ($ in millions) Amount Maturity Revolving Credit Facility $6,500 April 2031 Revolving Credit Facility 1,500 April 2029 Cash and Cash Equivalents 418 Commercial Paper Outstanding (975) Net Available Liquidity $7,443 Note: Rating agency views as calculated by AEP and may not include all adjustments that could be made by the rating agencies.Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Calculation is based on Moody’s Credit Committee view. Under Moody’s External view, FFO to debt would be 14.3% with the difference attributable to securitization. Refer to Appendix for the FFO to debt reconciliation..
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32 ($ in millions) Reconciliation of Total Debt to Adjusted Total Debt ($M)Reconciliation of Operating Income to FFO ($M) As of 9/30/2026 Total Debt (incl. current maturities) (GAAP) $54,416 Junior Subordinated Debentures (50%) (2,375) Accessible Cash and Investments (719) Securitization Bonds (2,287) Spent Nuclear Fuel Trust (339) Finance Lease Obligations 152 Operating Leases 679 Asset Retirement Obligations 1,352 OVEC Debt 379 Adjusted Total Debt (non-GAAP) $51,258 12 Months Ended 9/30/2026 Operating Income (GAAP) $5,534 Depreciation and Amortization 3,656 Cash Paid for Interest, net (2,127) Operating Lease Interest (29) Cash Paid for Income Taxes 109 Capitalized Interest (182) Nuclear Fuel Amortization 123 Securitization Debt Amortization and Interest (29) Operating Lease Payments 114 Junior Subordinated Debentures Interest 133 Asset Retirement Obligations - Accretion Expense 170 Stock Compensation 53 Funds Flow from Operations (FFO) (non-GAAP) $7,525 Note: S&P’s view as calculated by AEP and may not include all adjustments that could be made by the rating agency. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Third Quarter FFO to Total Debt – S&P S&P FFO to Debt as of 9/30/2026 was 14.7%.
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33 Reconciliation of Total Debt to Adjusted Total Debt ($M)Reconciliation of Cash Flow from Operations to FFO ($M) Third Quarter FFO to Total Debt – Moody’s Moody’s FFO to Debt as of 9/30/2026 was 14.8%.1 12 Months Ended 9/30/2026 Cash Flow from Operations (GAAP) $7,582 Changes in Working Capital 29 Operating Lease Payments 114 Capitalized Interest (182) Junior Subordinated Debentures Interest 133 Securitization Amortization (100) Deferred Fuel Recoveries (101) Funds Flow from Operations (FFO) (non-GAAP) $7,475 As of 9/30/2026 Total Debt (incl. current maturities) (GAAP) $54,416 Junior Subordinated Debentures (50%) (2,375) Securitization Bonds (2,287) Operating Leases 679 Finance Lease Obligations 152 Pension 85 Adjusted Total Debt (non-GAAP) $50,670 Note: Moody’s Credit Committee view as calculated by AEP and may not include all adjustments that could be made by the rating agency. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Calculation is based on Moody’s Credit Committee view. Under Moody’s External view, FFO to debt would be 14.3% with the difference attributable to securitization.
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34 Reconciliation of Total Debt to Adjusted Total Debt ($M)Reconciliation of Cash Flow from Operations to FFO ($M) Third Quarter FFO Leverage – Fitch Fitch’s FFO Leverage as of 9/30/2026 was 5.1x. 12 Months Ended 9/30/2026 Cash Flow from Operations (GAAP) $7,582 Securitization Amortization (100) Amortization for Finance Lease (62) Accounts Receivables, Net 562 Fuel, Materials & Supplies 198 Accounts Payable, Net (528) Accrued Taxes 180 Deferred Fuel Recoveries (101) Net Interest Paid/Received 2,130 Funds Flow from Operations (FFO) (non-GAAP) $9,861 As of 9/30/2026 Total Debt (incl. current maturities) (GAAP) $54,416 Junior Subordinated Debentures (50%) (2,375) Securitization Bonds (2,262) Spent Nuclear Fuel Trust (339) Debt Issuance Costs 428 Adjusted Total Debt (non-GAAP) $49,868 Note: Fitch’s view as calculated by AEP and may not include all adjustments that could be made by the rating agency. Operating earnings,operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”.
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35 $M Earnings Per Share Q3-25 Q3-26 Change Q3-25 Q3-26 Change Reported GAAP Earnings $972 $1,187 $215 $1.82 $2.18 $0.36 Non-Operating Items: Wholesale Customer Contract Agreements1 - 18 18 - 0.03 0.03 Impact of Ohio Legislation2 (8) - 8 (0.02) - 0.02 Mark-to-Market Impact of Commodity Hedging Activities3 (1) 11 12 - 0.02 0.02 Operating Earnings $963 $1,216 $253 $1.80 $2.23 $0.43 Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Items recorded in the VIU segment. 2. Items recorded in the T&D segment. 3. Items recorded across multiple segments. Third Quarter Earnings Reconciliation Weighted average number of shares outstanding: 544M Q3 2026 and 535M Q3 2025.
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36 $ in millions Earnings Per Share YTD-25 YTD-26 Change YTD-25 YTD-26 Change Reported GAAP Earnings $2,998 $ 2,774 ($224) $5.61 $5.10 ($0.51) Non-Operating Items: Wholesale Customer Contract Agreements1 - 36 36 - 0.06 0.06 Impact of the West Virginia Commission Order1 - (28) (28) - (0.05) (0.05) Mark-to-Market Impact of Commodity Hedging Activities2 6 25 19 0.01 0.05 0.04 Pirkey Plant Partial Disallowance1 - 25 25 - 0.05 0.05 Unified Tracker Mechanism Partial Disallowance3 - 17 17 - 0.03 0.03 FERC NOLC Order2 (480) - 480 (0.90) - 0.90 Impact of Ohio Legislation3 19 - (19) 0.04 - (0.04) Sale of AEP Onsite Partners4 9 - (9) 0.02 - (0.02) Operating Earnings $2,552 $2,849 $297 $4.78 $5.24 $0.46 Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Items recorded in the VIU segment. 2. Items recorded in multiple segments. 3. Items recorded in the T&D segment. 4. Items recorded mainly in the G&M segment. YTD Earnings Reconciliation Weighted average number of shares outstanding: 544M YTD 2026 and 534M YTD 2025.
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37 Rate Performance, Net of Offsets ($M) Q3-26 vs. Q3-25 APCo2 $22 I&M $1 KPCo $16 PSO $114 SWEPCO $56 Total $209 Impact on Operating EPS $0.31 Weather Impact ($M) Q3-26 vs. Q3-25 Q3-26 vs. Normal APCo2 $21 $13 I&M $1 $6 KPCo $1 $6 PSO $56 $48 SWEPCO $20 $33 Total $99 $106 Impact on Operating EPS $0.15 $0.15 Retail Load1 (Weather Normalized) Q3-26 vs. Q3-25 APCo2 (1.0%) I&M 15.9% KPCo 1.7% PSO (0.6%) SWEPCO 1.8% Total 3.2% Impact on Operating EPS3 $0.07 Rate Changes Weather Impact Normalized Sales Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2. APCo also includes WPCo and KGPCo. 3. Includes EPS impact of accrued revenues. VIUs Third Quarter Performance
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38 Rate Performance, Net of Offsets ($M) YTD-26 vs. YTD-25 APCo2 $63 I&M $8 KPCo $25 PSO $232 SWEPCO $149 Total $477 Impact on Operating EPS $0.70 Weather Impact ($M) YTD-26 vs. YTD-25 YTD-26 vs. Normal APCo2 $15 $17 I&M ($8) ($6) KPCo - $6 PSO $62 $47 SWEPCO $3 $36 Total $72 $100 Impact on Operating EPS $0.11 $0.15 Retail Load1 (weather normalized) YTD-26 vs. YTD-25 APCo2 (1.0%) I&M 18.7% KPCo (4.1%) PSO (0.4%) SWEPCO 2.4% Total 3.6% Impact on Operating EPS3 $0.24 Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2. APCo also includes WPCo and KGPCo. 3. Includes EPS impact of accrued revenues. Rate Changes Weather Impact Normalized Sales VIUs YTD Performance
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39 Rate Performance, Net of Offsets ($M) Q3-26 vs. Q3-25 AEP Texas $16 Ohio Power Company $35 Total $51 Impact on Operating EPS $0.07 Weather Impact ($M) Q3-26 vs. Q3-25 Q3-26 vs. Normal AEP Texas $14 $16 Ohio Power Company $5 $7 Total $19 $23 Impact on Operating EPS $0.03 $0.03 Retail Load1 (weather normalized) Q3-26 vs. Q3-25 AEP Texas 10.8% Ohio Power Company 11.6% Total 11.2% Impact on Operating EPS2 - Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2. Includes EPS impact of accrued revenues. Rate Changes Weather Impact Normalized Sales T&D Utilities Third Quarter Performance
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40 Rate Performance, Net of Offsets ($M) YTD-26 vs. YTD-25 AEP Texas $40 Ohio Power Company $70 Total $110 Impact on Operating EPS $0.16 Weather Impact ($M) YTD-26 vs. YTD-25 YTD-26 vs. Normal AEP Texas ($6) $15 Ohio Power Company ($14) $5 Total ($20) $20 Impact on Operating EPS $0.03 $0.03 Retail Load1 (weather normalized) YTD-26 vs. YTD-25 AEP Texas 10.5% Ohio Power Company 15.4% Total 13.1% Impact on Operating EPS2 $0.05 Rate Changes Weather Impact Normalized Sales Note: Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 1. Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2. Includes EPS impact of accrued revenues. T&D Utilities YTD Performance