Slides
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Second Quarter 2026 Earnings July 30, 2026
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Cautionary Note Regarding Forward - Looking Statements 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 legislation or regulation adopted in the states in which we operate or federal legislation or regulation adopted that alters the regulatory framework or that prevents the 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’s liability 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 associated with the completion of the 2026-2030 capital investment plan, including shortages or delays in labor, materials, equipment or parts, the impact of prolonged or recurring U.S. federal government shutdowns on AEP’s operations, regulatory approvals, and financial performanceincluding 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 capitalplans, 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 affordabilityconcerns 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. 2 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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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 second quarter of 2026, the estimated earnings per share on a GAAP basis would be $6.16 to $6.46 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 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Accelerating Growth and Driving Value High-quality, pure-play electric utility strategically positioned in growth regions, rooted in innovation and actively meeting unprecedented customer demand. VISION Improve customers’ lives with reliable, affordable power FOOTPRINT 5.6M customers throughout high-growth regions 33 GW of diverse owned and contracted generating capacity 40K transmission miles and 252K distribution miles Own and operate the largest transmission network in the U.S. FINANCIAL SUMMARY $78B 5-year capital plan plus line of sight to over $10B of additional capital ~11% rate base CAGR expected through 2030 ~69 GW1 incremental contracted load by 2030 7%-9% annual operating earnings growth rate; expected CAGR of greater than 9% through 2030 KEY GROWTH STATES: INDIANA, OHIO, OKLAHOMA AND TEXAS 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. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. 4 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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7%-9% Annual Operating Earnings Growth Rate With an expected CAGR of greater than 9% through 2030 69 GW Incremental Contracted Load by 2030 Up from 63 GW disclosed on Q1 2026 call Financial Guidance Overview 1 Includes AEP Transmission Holdco and transmission investments in AEP operating companies. Calculated using 2026E transmission earnings of $3.34 as a percentage of the raised 2026 operating guidance midpoint of $6.40. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. $78B Updated Capital Plan 2026-2030 14%-15% Targeted FFO/Debt Range 2026-2030 ~3% Dividend Yield ~11% Rate Base Growth CAGR through 2030 ~10%-13% Total Annual Expected Shareholder Return (TSR) 2026-2030 Outlook $6.25-$6.55 Raised 2026 Operating EPS Guidance Range $13B 2026 Capital Investment >50% 2026 Operating Earnings from High- Growth Transmission Business1 7 GW Contracted Load Additions in 2026 2026 Guidance Significant infrastructure investment and operational excellence are driving strong financial results. + Over $10B Line of Sight Capital 2026-2030 5 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Key Themes and Highlights 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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Key Themes Anchored by strong financial performance, enhanced affordability, outsized growth, and regulatory and operational excellence, we are delivering differential value for customers and shareholders. Creating Differential Value Through Disciplined Execution Enhancing Financial Performance Driving Customer Affordability Capturing System-wide Growth Improving Regulatory and Operational Outcomes 7 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Second Quarter Key Highlights 1 Based on 2025 guidance midpoint. 2 Refer to Appendix for the GAAP to operating earnings reconciliation. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Execution is key to capture generational growth, reinforcing confidence in financial performance. ✓ Supported affordability with an expected $16B of cost offsets for residential customers from fully executed take -or-pay Electric Service Agreements (ESAs) within the Vertically Integrated Utilities (VIUs) over the life of the agreements ✓ Secured ~$5B in DOE loans and almost $400M in DOE grants, delivering an estimated $1.4B in customer savings over the life of the loans and grants ✓ Increased incremental contracted load by 6 GW to 69 GW, driven by fully executed Letters of Agreement (LOAs) in ERCOT ✓ Advanced the $78B capital plan by securing labor and critical resources, executing the turbine strategy and forming strategic partnerships to accelerate infrastructure development; line of sight to over $10B of incremental capital ✓ Successfully advanced rate cases and securitization initiatives across key jurisdictions ✓ Obtained approval of large load tariffs in five of the eight states where filings have been submitted; targeting to obtain approval of remaining tariffs by end of 2026 Driving Customer Affordability Capturing System- wide Growth Improving Regulatory and Operational Outcomes ✓ Raised 2026 operating EPS guidance to $6.25-$6.55 per share, reflecting confidence in 2026 full-year performance ✓ Reaffirmed annual operating earnings growth rate of 7%-9% with expected CAGR of greater than 9% through 20301 ✓ Significantly de-risked the financing plan with $3B equity forwards executed in May 2026, covering all currently anticipated marketed growth equity needs for the $78B capital plan ✓ Delivered Q2 2026 EPS of $1.31 (GAAP) and $1.36 (operating); YTD 2026 EPS of $2.92 (GAAP) and $3.01 (operating) 2 Enhancing Financial Performance 8 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Large load growth supports affordability • Forecasting up to $16B of cost offsets generated for existing residential customers from fully executed take-or-pay ESAs within the VIUs through their allocated contributions to fixed expenses over the life of the agreements • Implemented rate reductions in AEP Ohio and I&M enabled by large load growth and filing structures designed to support customer affordability Delivering Affordable and Reliable Power Residential rate impacts are mitigated through load growth, including 69 GW of contracted load by 2030 (up from 63 GW disclosed last quarter), as well as disciplined cost management and efficient financing. Disciplined cost management with O&M increasing modestly while rate base grew at roughly double the pace $3.0B $1.1B 2022A $2.9B $1.2B 2023A $2.8B $1.5B 2024A $3.1B $1.5B 2025A $3.3B $1.5B 2026E Untracked O&M Tracked O&M 2022A 2026E $62B $85B Total AEP Rate Base (~8% CAGR from 2022-2026) Focused customer service with disciplined cost management • Improved customer average interruption duration index, demonstrating meaningful progress in strengthening customer service through more reliable power • Focused O&M efficiency amid rapid rate base growth Federal grants and U.S. Department of Energy (DOE) loans provide customer savings • Received award notices totaling almost $400M in grants to deliver customer savings over the grant periods, including recent June 2026 awards supporting generation resources • Executed on ~$5B of DOE loans for transmission projects, including an up to $3.3B loan for AEP Texas that closed in July 2026; the total loan portfolio is estimated to deliver ~$1B of customer savings over the life of the loans through lower financing costs 9 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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✓ Reached constructive settlement with select intervenors in June 2026 for the PSO base case including full tracking of the SPP transmission cost Recent Regulatory Progress Focused operational excellence results in improved regulatory outcomes. ✓ Order received in April 2026 for the AEP Ohio distribution base case establishing new revenue caps for the Distribution Investment Rider and providing a rate reduction to support customer affordability ✓ Order received in January 2026 approving I&M’s Expedited Generation Resource Plan in Indiana, allowing I&M to move forward with resource additions in approximately half the time required under traditional methods ✓ Order received in January 2026 for the Arkansas base case, approving an $85M revenue increase and an ROE of 9.65% ✓ Reconsideration filing order received in February 2026 for the West Virginia base case, increasing the authorized ROE to 9.75% from the original 9.25% in the August 2025 order ✓ Order received in February 2026 approving SWEPCO Arkansas’ request to construct new natural gas plants including a flex-up option; in July 2026, settlement agreements were filed in Louisiana and Texas supporting project approval ✓ Order received in March 2026 for the Louisiana Formula Rate Plan, increasing the authorized ROE to 9.7% ✓ Implemented a June 2026 rate reduction for I&M customers and announced plans to file an Indiana base rate case later this year to reduce base rates and support affordability ✓ Order received in April 2026 for the West Virginia 2024 Modified Rate Base Cost (MRBC) infrastructure investment tracker authorizing recovery for the full applicable period ✓ Reached a unanimous settlement in principlein April 2026 for the Texas base case, commission order is expected in Q4 2026 ✓ Filed a Virginia base rate case in May 2026 with the lowest increase in a base rate request in nearly 30 years, supported by $1.4B of securitization ✓ Order received in June 2026 approving Virginia large load tariff ✓ Order received in May 2026 approving PSO’s request to procure 1.3 GW of generation resources 10 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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T r e v o r M i h a l i k C F O Second Quarter 2026 Results and Financial Growth Outlook
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0 Second Quarter Operating Earnings Drivers Results were impacted by the timing of the prior year Transmission minority interest sale and income taxes; Transmission Holdco earnings are expected to be favorable year-over-year by end of 2026, while income tax impacts are expected to reverse by the end of the year. 12 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 2025 Actual VERTICALLY INTEGRATED UTILITIES TRANSMISSION AND DISTRIBUTION UTILITIES AEP TRANSMISSION HOLDCO GENERATION & MARKETING CORPORATE AND OTHER 2026 Actual 2026 Actual Operating EPS $0.56 $0.44 $0.41 $0.17 $(0.22) $1.36 0.02 (0.01) (0.08) $1.36 Per Share $1.43 Per Share Rate Changes $0.21 Normalized Sales $0.10 Transmission Revenue $0.05 Reliability Spend $(0.09) O&M $(0.05) Depreciation $(0.06) Net Interest $(0.08) Other Taxes $(0.03) Other $(0.05) Rate Changes $0.06 Weather $(0.02) Transmission Revenue $0.06 Reliability Spend $(0.01) O&M $(0.01) Other Taxes $(0.04) Other $(0.02) Retail $(0.06) Wholesale and Other $0.06 O&M $(0.01) Net Interest $(0.02) Income Taxes $(0.06) Other $0.01 0.00 0.00 O&M $(0.01) Other Taxes $(0.01) Other $0.01 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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0 YTD 2026 Operating Earnings Drivers 13 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 2025 Actual VERTICALLY INTEGRATED UTILITIES TRANSMISSION AND DISTRIBUTION UTILITIES AEP TRANSMISSION HOLDCO GENERATION & MARKETING CORPORATE AND OTHER 2026 Actual 2026 Actual Operating EPS $1.41 $0.88 $0.80 $0.33 $(0.41) $3.01 0.10 (0.06) 0.02 (0.23) $3.01 Per Share $2.98 Per Share Rate Changes $0.40 Weather $(0.04) Normalized Sales $0.17 Transmission Revenue $0.10 Reliability Spend $(0.23) O&M $(0.06) Depreciation $(0.12) Other $(0.02) Rate Changes $0.09 Weather $(0.06) Normalized Sales $0.04 Transmission Revenue $0.13 Reliability Spend $(0.04) O&M ($0.02) Other $(0.04) Retail $(0.10) Wholesale and Other $0.11 Income Taxes $0.01 O&M $(0.04) Net Interest $(0.04) Income Taxes $(0.12) Other $(0.03) 0.20 O&M $(0.03) Other Taxes $(0.03) AEP’s first half performance plus expected results for the remainder of the year provide the confidence to increase our 2026 operating EPS guidance range to $6.25-$6.55 per share. 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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2026-2030 Load Growth 1 Includes crypto customers. 3 10 23 38 45 4 6 9 13 183 6 2026E 1 2027E 2 2028E 2029E 2030E 7 GW 17 GW 34 GW 54 GW 69 GW SPP PJM ERCOT Cumulative Contracted Load Additions 90% 10% 69 GW 6% 1% 1% 1% 66% 7% 18% 69 GW Texas (~45 GW) Ohio (~12 GW) Oklahoma (~5 GW) Indiana (~4 GW) Kentucky (~1 GW) Louisiana (~1 GW) Virginia (~1 GW) Data Centers1 Industrials Incremental contracted load of 69 GW by 2030 backed by fully executed ESAs and LOAs and further supported by ~195 GW of active projects in the interconnection queue. 14 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Load Growth Summary – 69 GW of Contracted Load by 2030 45 GW in ERCOT 18 GW in PJM 6 GW in SPP 69 GW Up 6 GW from 63 GW disclosed on Q1 2026 call 100% Senate Bill 6 (SB6) compliant load backed by LOAs; ERCOT contracting structure allows for LOAs only 100% LOAs and ~95% ESAs 100% LOAs and ~55% ESAs; continue to convert new load development into ESAs as discussions progress GW by Year, Totaling 69 GW (2026-2030) 2026E 2027E 2028E 2029E 2030E 7 GW 10 GW 17 GW 20 GW 15 GW
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ERCOT Batch Zero Submission AEP Texas submitted 45 GW 1,2 of projects through ERCOT’s Batch Zero process with 100% of the submitted load backed by nearly $2B in customer cash or collateral commitments. SB6 Criteria 1. Show financial capability or commitment; AEP Texas requires upfront construction funding as part of the LOA 2. Pay upfront ERCOT study fee 3. Provide proof of site control 4. Disclose intended sources of generation 5. Disclose other active projects that could affect the request Batch Zero Review Process Timeline ✓ June 2026: ERCOT formally approves Batch Zero review process ✓ July 2026: AEP and large-load customers submit full project information to ERCOT • August 2026: ERCOT finalizes the list of projects eligible for inclusion in a Batch Zero category • April 2027: ERCOT delivers Batch Zero results providing each project with its allocated amount of reliable electric capacity • Summer 2027: ERCOT opens the Batch One review process AEP Texas Batch Zero Submission 45 GW1,2 Batch Zero Submission (2027-2032) 1 New load timing will be influenced by resource availability; ERCOT demand growth based on customer-signed energization dates is significantly larger than the current peak demand of approximately 8 GW; with roughly 90% representing data center customers including crypto-related operations. 2 Within AEP Texas’ 45 GW of load by 2030 shown on slide 14, 5 GW was not required to go through Batch Zero review process, mainly relates to projects energized prior to 7/10/2026 and loads below 75 MW. 3 The 16 GW of base load includes 2 GW of load eligible for designation as either base load or studied (allocated) load; ERCOT will review the studies by 8/7/2026 and finalize the classification of this load.15 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 5 GW Beyond 2030 40 GW by 2030 16 GW3 Base Load 29 GW Studied Load
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Closing Remarks 1 Based on 2025 guidance midpoint. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. ✓ Load growth drives expected cost offsets of $16B from fully executed take-or-pay ESAs within VIUs over the life of the agreements ✓ Focused on customer affordability, delivering estimated $1.4B of customer savings through DOE grants and loans ✓ Strong customer demand driven by 69 GW of incremental load growth by 2030; additional clarity on timing of ERCOT load expected as batch process review progresses ✓ Advanced the $78B capital plan with line of sight to over $10B of incremental capital opportunities beyond the base plan ✓ Positioned for successful execution by securing critical resources and advancing generation strategy with 13 GW of secured turbine capacity through 2031 ✓ Demonstrated a customer-focused approach to regulatory outcomes Driving Customer Affordability Capturing System- wide Growth Improving Regulatory and Operational Outcomes ✓ Raised 2026 operating EPS guidance to $6.25-$6.55 per share ✓ Reaffirmed annual operating earnings growth rate of 7%-9% with expected CAGR of greater than 9% through 20301 ✓ De-risked the current financing plan and positioned AEP to focus on accelerated growth Enhancing Financial Performance 16 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Appendix 1 Forecasted Highlights
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New data centers announced in 2026 Contracted customers must meet high credit standards through investment grade credit quality, parent guarantees or credit support compliant with tariff requirements Diverse Commercial and Industrial Footprint 1 Companies shown in the graph do not reflect all projects included in the load forecast and AEP load data are not publicly disclosed for most projects. 1 Steel Manufacturing Apple Grove, WV Data Centers Columbus, OH Data Center Piketon, OH 10 GW Campus at Buildout Stargate Data Center Abilene, TX Data Centers Tulsa, OK Data Centers Shreveport, LA Data Centers Fort Wayne, IN Data Centers Granger, IN LNG Expansion Corpus Christi, TX Data Centers Putnam County, WV Muskie Data Center Grayson, KY Diverse customer base provides a foundation for long-term infrastructure partnerships and drives economic growth. Large Load Growth Drives Community and Economic Benefits ✓Pay their fair share ✓Drive long-term affordability by sharing grid costs ✓Support a stronger, more reliable grid ✓Create meaningful benefits for local communities through job creation and workforce development 18 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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Innovative Data Center and Large Load Tariffs Advancing Affordability Operating Companies Minimum Threshold Long-term Contract Period Minimum Demand Charge1,2 Termination Fee Collateral Required Status AEP Ohio 25 MW Individual Site, Aggregated 12 Years (Includes 4-year ramp) 85% After Year 5, minimum bills for remaining term (max 3 years) Yes ✓ Approved APCo West Virginia 100 MW Individual Site, 150 MW Aggregated 12-17 Years (Depends on ramp period) 80% After Year 5, minimum bills for remaining term (max 5 years) Yes ✓ Approved I&M Indiana 70 MW Individual Site, 150 MW Aggregated 12-17 Years (Depends on ramp period) 80% After Year 5, minimum bills for remaining term (max 5 years) Yes ✓ Approved KPCo Kentucky 150 MW Individual Site 20 Years 90% After Year 5, minimum bills for remaining term (max 5 years) Yes ✓ Approved APCo Virginia 100 MW Individual Site, 150 MW Aggregated 14 Years (Includes 4-year ramp) 80% After Year 5, minimum bills for remaining term (max 5 years) Yes Approved 6/1/2026 I&M Michigan 50 MW Individual Site, Aggregated 15-20 Years (Depends on ramp period) 90% After Year 5, minimum bills for remaining term (max 5 years) Pending Pending PSO Oklahoma 75 MW+ Individual Site, Aggregated 10-75 MW Individual Site, Aggregated 10-15 years for 75 MW+ 2-5 years for 10-75 MW (Depends on ramp period) 80% After Year 5, minimum bills for remaining term (max 5 years) for 75 MW+ After Year 2, minimum bills for remaining term (max 2 years) for 10-75 MW Pending Pending SWEPCO Texas 75 MW Aggregated 12-17 Years (Depends on ramp period) Percentage not publicly disclosed 12 years plus any designated ramp period Pending Pending 1 Percentage may be higher based on prior period’s peak demand. 2 Indiana, Michigan, Texas, Virginia and West Virginia tariff minimum bill calculations also include an energy component. Collaborated with stakeholders and pioneered data center and large load tariff solutions to support customer and system needs, including our key growth states of Indiana, Ohio, Oklahoma and Texas. 19 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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2026-2030 Annual Operating Earnings Growth Rate of 7%-9% 2025 2026 Original Guidance 2027 Outlook 2028 Outlook 2029 Outlook 2030 Outlook ~8% growth off 2025 guidance midpoint 2025 guidance midpoint (BASE) Raised 2026 operating EPS guidance to $6.25-$6.55 per share reflecting confidence in 2026 performance; reaffirmed annual operating earnings growth rate of 7%-9% with an expected CAGR of greater than 9%1 through 2030 based on the 2025 guidance midpoint. $6.15-$6.45 Original Operating EPS$5.85 Operating EPS Accelerated growth aligns with the 2028 capital peak driven by transmission buildout, generation project advancement and positive legislative developments 1 CAGR reflects the current $78B capital plan through 2030. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Growth off 2026 original operating guidance midpoint of $6.30 20 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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$17B Distribution $20B Transmission$13B Transmission Holdco $8B Renewables $13B New Generation $3B Other Gen $4B Corp1 $78B 2026-2030 Capital Forecast Line of sight to over $10B of additional capital for 2026-2030 22% Distribution 42% Transmission 31% Generation 1 Includes AEP and operating companies. Distribution $17B Transmission $33B Generation $24B Other $4B 5% Other Base capital plan of $78B supports ~11% rate base CAGR through 2030 Deep backlog of over $10B in incremental opportunities to be addressed in the annual capital update this fall. $15 $16 $18 $20 $23 $26 $23 $25 $29 $33 $36 $40 $42 $44 $48 $57 $64 $68 VIU T&D Transmission Holdco/JVs $80 $85 $95 $110 $123 $134 2026-2030 Investment Growth Projects Status Company/Segment In-Service Date Incremental Capex ($B) Fuel Cells for the Wyoming Project AEP expects to advance and commercialize the Wyoming fuel cell project, but retains robust financial protections if conditions in the agreement are not met Generation and Marketing Expected to be in service by 2028 to qualify for full Investment Tax Credits $4 Piketon Transmission Opportunity AEP continues to work closely with SB Energy to advance the projects AEP Ohio Expected power to begin flowing to the site in 2029 $4.2 New Generation Resources Additional generation opportunities across our footprint to meet increased customer demand Vertically Integrated Utilities Expected to enter service over multiple years >$2 21 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 2025A 2026E 2027E 2028E 2029E 2030E
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Expected $55B transmission rate base in our existing plan through 2030 delivers significant shareholder value. 2026-2030 High-Growth Transmission $15 $16 $18 $20 $23 $26 $17 $18 $20 $23 $26 $29 2025A 2026E 2027E 2028E 2029E 2030E $32 $34 $38 $43 $49 $55 EPS Contributions ($/Share) 2025A AEP Transmission Holdco1 $1.51 Transmission Investments in AEP Operating Companies $1.67 2026E $1.55 $1.79 Rate base of transmission investments in AEP operating companies Rate base of AEP Transmission Holdco Transmission Rate Base ($ in billions) 1 Reflects the Ohio and I&M Transcos minority interest transaction closed in June 2025. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Total $3.18 $3.34 22 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n
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1 Includes Wheeling Power Company.. 2026-2030 Capital Forecast by Subsidiary Capital plans are continuously optimized which may result in redeployment between timing, functions and companies. Capital plan is fueled by transmission buildout and generation project advancements. 37% 22% 21% 16% 4% Generation $24B I&M PSO APCo1 SWEPCO Other (includes KPCo and AEG) 28% 20% 15% 13% 11% 9% 4% Distribution $17B AEP Texas AEP Ohio APCo1 PSO I&M SWEPCO Other (includes KPCo and KGPCo) 34% 39% 10% 6% 5% 6% Transmission $33B AEP Texas AEP Transmission Holdco SWEPCO AEP Ohio APCo1 Other (includes PSO, I&M, KPCo and KGPCo) 23 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n ($ in millions, excludes AFUDC) 2026E 2027E 2028E 2029E 2030E Total AEP Texas Inc. $2,351 $2,599 $3,738 $3,781 $4,333 $16,802 AEP Transmission Holdco 1,615 2,065 2,909 3,125 3,141 12,855 Indiana Michigan Power Company 2,218 2,718 2,548 3,239 1,086 11,809 Appalachian Power Company1 1,608 1,282 3,027 1,722 1,840 9,479 Southwestern Electric Power Company 1,302 1,387 1,850 2,225 2,178 8,942 Public Service Company of Oklahoma 1,697 2,329 1,999 1,129 1,367 8,521 AEP Ohio 1,203 1,192 1,136 1,193 1,011 5,735 Kentucky Power Company 314 341 404 517 408 1,984 Kingsport Power Company 23 25 25 25 22 120 AEP Generating Company 13 8 3 - - 24 Other 493 352 279 279 263 1,666 Total Capital Contributions $12,837 $14,298 $17,918 $17,235 $15,649 $77,937
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1 Other investing mainly relates to AFUDC and timing of nuclear fuel acquisitions. 2 Dividends per share remain constant until approved by Board of Directors. Dividends evaluated by Board of Directors each quarter and may be adjusted based on capital allocation priorities and other strategic considerations. Target payout ratio range is 50%-60% of operating earnings. 2026-2030 Financing Plan ($ in millions) 2026E 2027E 2028E-2030E Total Cash from Operations $ 7,800 $ 8,600 $ 30,700 $ 47,100 Capital and JV Equity Contribution (12,900) (14,200) (50,800) (77,900) Other Investing Activities1 (200) (200) (700) (1,100) Common Dividends2 (2,100) (2,200) (6,800) (11,100) Required Capital $ (7,400) $ (8,000) $ (27,600) $ (43,000) Financing Required Capital $ (7,400) $ (8,000) $ (27,600) $ (43,000) Long-term Debt Maturities (2,300) (1,500) (7,200) (11,000) Securitization Amortizations (200) (300) (700) (1,200) Equity: Dividend Reinvestment Plan 180 180 540 900 ATM Program3 1,000 - 3,000 ($1B per year) 4,000 Settlement of March 2025 / May 2026 Equity Forwards 1,800 - 3,000 4,800 Debt Capital Market Activity4 $ (6,920) $ (9,620) $ (28,960) $ (45,500) Financial Metrics Debt to Capitalization (GAAP) Approximately 60%-63% FFO/Debt (S&P and Moody’s) 14%-15% Targeted Range Successfully fulfilled the $3B marketed growth equity needed to support the $78B capital plan; AEP is well positioned to focus on accelerating growth supported by a de-risked financing plan. 24 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 3 Executed $665M of ATM equity issuances in the first half of 2026. 4 Could include equity-like instruments. Actual cash flows will vary by company and jurisdiction 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”.
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2,208,753 Demand Driving Generation Diversity 1 Resource additions are from Integrated Resource Plans (IRP) filings based on current regulations; alternative forms of generation may be added based on specific customer requests. 2 Investments in new generation resources will be subject to market availability of economic projects, regulatory preferences and approvals, and RTO capacity requirements. 3 Natural gas additions may include peaking units and fuel switching to provide reliable, affordable and flexible power. 4 RFPs represent up-to MW capacity values; related regulatory filings will take into consideration commission preferences including owned and contracted resources. 2025 | 2026 AR – FEB Completed IN – MAR Completed WV – OCT Completed VA VCEA – MAY Completed VA VCEA – MAY Completed IRP Filings Company APCo RFPs Issued May-26 All Source (Renewables and Natural Gas) 800 MW Renewable Resources Reg. Filings and Approvals Projected In-service Dates SWEPCO May-26 3,000 MW of SPP accredited capacity Q1-27 - Q4-27 Q1-27 - Q1-28 2029 2031 2026-20351 Projected Resource Needs RFPs In Progress4 Nameplate MW2 Solar APCo 1,926 Wind Storage Total 605 252 5,854 600 598 - Significant generation is required to meet new demand. Total 6,378 5,056 502 27,235 I&M 2,959 3,100 50 12,799 SWEPCO 4,311 KPCo 450 PSO 893 753 200 3,821 Nat. Gas3 6,690 3,071 3,113 1,975 450 15,299 - - - PSO Jan-26 25 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 4,000 MW of SPP accredited capacity Q3-26 - Q3-27 2029
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Appendix 2 Sales and Regulatory Progress
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C&I GWh Sales1 Six Months Ended 6/30/2026 % Change vs. Same Period Prior Year C&I Revenues2 Six Months Ended 6/30/2026 (Including Minimum Demand Charges) % Change vs. Same Period Prior Year C&I Sales Trends and Revenues in 2026 1 Load figures are billed retail sales excluding firm wholesale load and are not weather normalized. 2 Reflects non-fuel revenues. Financial performance supported by rising Commercial and Industrial (C&I) sales trends and further strengthened by minimum demand charges in data center and large load customer agreements. 27 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Vertically Integrated C&I Sales Total C&I Sales 6% 13% Vertically Integrated C&I Revenues Total C&I Revenues 18% 15% Revenues are protected by minimum demand requirements in customer agreements, providing revenue stability even if customer ramps are delayed
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9.4% 9.0% 6.7% 4.1% 12.7% 11.0%3 6.6% 8.4% 10.0% 2% 4% 6% 8% 10% 12% 14% Regulated Earned Returns 1 Calculated based on non-GAAP operating earnings, not weather normalized. 2 Calculated based on adjusted equity. Refer to Appendix for the GAAP to adjusted equity reconciliation. 3 Excludes the impact of income from Rockport Unit 2. I&M AEP OhioTransmission Holdco AEP Texas PSO4APCo4SWEPCO4 KPCo Forecasted Regulated ROE is expected to improve to approximately 9.5% by 2030. 28 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 8.8% 2023 9.05% 2024 9.1% 2025 9.2% 2026E 2027E 2028E 2029E 9.5% 2030E Historical and Projected Regulated ROE Trend 9.2% earned ROE1,2 as of twelve months ended 6/30/2026 9.2% Earned ROE1,2 4 Base rate cases pending/order recently received. 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”.
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Current Rate Case Activity Achieve positive regulatory outcomes to advance affordability, system reliability, resiliency and security. 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 (Less $25M D&A) Net Revenue Increase $36M Test Year 12/31/2025 Procedural Schedule Intervenor Testimony 8/26/2026 Rebuttal Testimony 9/30/2026 Hearing 10/20/2026 Expected Effective Date March 2027 Expected Commission Order Q1 2027 1 Does not include $298M moving from rider recovery to base rates and production tax credits. 2 Does not include $69M moving from rider recovery to base rates. 3 Reached a settlement in principle and details have not yet been publicly filed. APCo – Virginia SWEPCO – Texas 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 Increase1 $299M (Less $118M D&A) Net Revenue Increase $181M Test Year 7/31/2025 Procedural Schedule Expected Effective Date July 2026 Expected Commission Order Q3 2026 PSO 29 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Docket # 58819 Filing Date 10/14/2025 Requested Rate Base $2.4B Requested ROE 10.75% Cap Structure 48%D / 52%E Gross Revenue Increase2 $95M (Less $11M D&A) Net Revenue Increase $84M Test Year 3/31/2025 Procedural Schedule3 Expected Effective Date March 2026 Expected Commission Order Q4 2026
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Appendix 3 Second Quarter Financial Metrics
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Second Quarter Liquidity and Credit Metrics S&P Moody’s Fitch Rating / Outlook BBB / Stable Baa2 / Stable BBB / Stable Credit Metric FFO/Debt: 14.6%1 FFO/Debt: 14.0%1 FFO Leverage: 5.3x Targeted Range 14%-15% 5.0x-5.5x Downgrade Threshold 13% Sustained 5.8x Sustained 1 Refer to Appendix for the FFO to debt reconciliation. Rating agency views as calculated by AEP and may not include all adjustments that could be made by the rating agencies. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. Liquidity Summary 6/30/2026 Credit Metrics Trailing 12 Months as of 6/30/2026 31 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n ($ in millions) Amount Maturity Revolving Credit Facility $ 6,500 April 2031 Revolving Credit Facility 1,500 April 2029 Plus Cash and Cash Equivalents 375 Less Commercial Paper Outstanding (1,125) Net Available Liquidity $ 7,250
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Second Quarter FFO to Total Debt – S&P S&P FFO to Debt as of 6/30/2026 was 14.6%. ($ in millions) ($ in millions) RECONCILIATION OF TOTAL DEBT TO ADJUSTED TOTAL DEBT 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”.32 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n RECONCILIATION OF OPERATING INCOME TO FFO As of 6/30/2026 Total Debt (incl. current maturities) (GAAP) $ 52,836 Junior Subordinated Debentures (50%) (2,375) Accessible Cash and Investments (610) Securitization Bonds (2,330) Spent Nuclear Fuel Trust (336) Finance Lease Obligations 156 Operating Leases 662 Asset Retirement Obligations 1,350 OVEC Debt 379 Adjusted Total Debt (non-GAAP) $ 49,732 12 Months Ended 6/30/2026 Operating Income (GAAP) $5,244 Depreciation and Amortization 3,510 Cash Paid for Interest, net (2,031) Operating Lease Interest (29) Cash Paid for Income Taxes 203 Capitalized Interest (166) Nuclear Fuel Amortization 121 Securitization Debt Amortization and Interest (36) Operating Lease Payments 113 Hybrid Interest Expense 112 Asset Retirement Obligations - Accretion Expense 170 Stock Compensation 53 Funds Flow from Operations (FFO) (non-GAAP) $ 7,264
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Second Quarter FFO to Total Debt – Moody’s Moody’s FFO to Debt as of 6/30/2026 was 14.0%. ($ in millions) ($ in millions) RECONCILIATION OF CASH FLOW FROM OPERATIONS TO FFO RECONCILIATION OF TOTAL DEBT TO ADJUSTED TOTAL DEBT Moody’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”.33 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 12 Months Ended 6/30/2026 Cash Flow from Operations (GAAP) $ 7,693 Changes in Working Capital (382) Operating Lease Depreciation 113 Capitalized Interest (166) Junior Subordinated Debentures Interest 112 Deferred Fuel Recoveries (205) Funds Flow from Operations (FFO) (non-GAAP) $ 7,165 As of 6/30/2026 Total Debt (incl. current maturities) (GAAP) $52,836 Junior Subordinated Debentures (50%) (2,375) Operating Leases 662 Finance Lease Obligations 156 Pension 85 Adjusted Total Debt (non-GAAP) $51,364
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Adjusted Average Equity 13-Month Average Ending 6/30/2026 Average Equity (GAAP) $ 37,988 13-Month Average Paid In Capital Associated with the 2025 Midwest Transmission Holdings Noncontrolling-Interest Transaction (1,790) Adjusted Average Equity (non-GAAP) $ 36,198 ($ in millions) 13-Month Average Equity Ending 6/30/2026. RECONCILIATION OF AVERAGE EQUITY GAAP TO NON-GAAP 34 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 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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Second Quarter Earnings Reconciliation Weighted average number of shares outstanding: 544M Q2 2026 and 534M Q2 2025. 35 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 1 Items recorded mainly or entirely in the VIU segment. 2 Items recorded mainly or entirely in the T&D segment. 3 Items recorded across multiple segments. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. $ in millions Earnings Per Share Q2-25 Q2-26 Change Q2-25 Q2-26 Change Reported GAAP Earnings $1,226 $713 ($513) $2.29 $1.31 ($0.98) Non-Operating Items: Wholesale Customer Contract Agreements1 - 18 18 - 0.03 0.03 Impact of Unified Tracker Mechanism Partial Disallowance2 - 17 17 - 0.03 0.03 Mark-to-Market Impact of Commodity Hedging Activities3 20 (6) (26) 0.04 (0.01) (0.05) FERC NOLC Order3 (480) - 480 (0.90) - 0.90 AEP Operating Earnings $766 $742 ($24) $1.43 $1.36 ($0.07)
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YTD Earnings Reconciliation Weighted average number of shares outstanding: 543M YTD 2026 and 534M YTD 2025. 36 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n 1 Items recorded mainly or entirely in the VIU segment. 2 Items recorded mainly or entirely in the T&D segment. 3 Items recorded across multiple segments. 4 Items recorded mainly or entirely in the G&M segment. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”. $ in millions Earnings Per Share YTD-25 YTD-26 Change YTD-25 YTD-26 Change Reported GAAP Earnings $2,026 $1,587 ($439) $3.80 $2.92 ($0.88) Non-Operating Items: Impact of the West Virginia Commission MRBC Order1 - (28) (28) - (0.05) (0.05) Pirkey Plant Partial Disallowance1 - 25 25 - 0.05 0.05 Wholesale Customer Contract Agreements1 - 18 18 - 0.03 0.03 Impact of Unified Tracker Mechanism Partial Disallowance2 - 17 17 - 0.03 0.03 Mark-to-Market Impact of Commodity Hedging Activities3 6 14 8 0.01 0.03 0.02 FERC NOLC Order3 (480) - 480 (0.90) - 0.90 Impact of Ohio Legislation2 28 - (28) 0.05 - (0.05) Sale of Distributed Resources Business4 9 - (9) 0.02 - (0.02) AEP Operating Earnings $1,589 $1,633 $44 $2.98 $3.01 $0.03
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Vertically Integrated Utilities Second Quarter Performance RATE CHANGES WEATHER IMPACT NORMALIZED SALES 1 Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2 APCo also includes WPCo and KGPCo. 3 Includes EPS impact of accrued revenues. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”.37 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Rate Performance, net of offsets ($ in millions) Q2-26 vs. Q2-25 APCo2 $15 I&M $2 KPCo $8 PSO $65 SWEPCO $51 Total $141 Impact on Operating EPS Weather Impact ($ in millions) Q2-26 vs. Q2-25 Q2-26 vs. Normal APCo2 ($3) ($1) I&M ($8) ($9) KPCo - $1 PSO $12 - SWEPCO ($7) $7 Total ($6) ($2) Impact on Operating EPS - - Retail Load1 (weather normalized) Q2-26 vs. Q2-25 APCo2 (0.5%) I&M 21.9% KPCo (4.3%) PSO (0.5%) SWEPCO 4.4% Total 4.7% Impact on Operating EPS3$0.21 $0.10
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Vertically Integrated Utilities YTD Performance RATE CHANGES WEATHER IMPACT NORMALIZED SALES 1 Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2 APCo also includes WPCo and KGPCo. 3 Includes EPS impact of accrued revenues. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”.38 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Rate Performance, net of offsets ($ in millions) YTD-26 vs. YTD-25 APCo2 $41 I&M $7 KPCo $9 PSO $118 SWEPCO $93 Total $268 Impact on Operating EPS Weather Impact ($ in millions) YTD-26 vs. YTD-25 YTD-26 vs. Normal APCo2 ($6) $4 I&M ($10) ($11) KPCo - - PSO $6 - SWEPCO ($17) $2 Total ($27) ($5) Impact on Operating EPS - Retail Load1 (weather normalized) YTD-26 vs. YTD-25 APCo2 (1.0%) I&M 20.3% KPCo (5.5%) PSO (0.2%) SWEPCO 2.7% Total 3.7% Impact on Operating EPS3$0.40 $0.17$0.04
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Transmission and Distribution Utilities Second Quarter Performance WEATHER IMPACT NORMALIZED SALES RATE CHANGES 39 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Rate Performance, net of offsets ($ in millions) Q2-26 vs. Q2-25 AEP Ohio $26 AEP Texas $14 Total $40 Impact on Operating EPS Weather Impact ($ in millions) Q2-26 vs. Q2-25 Q2-26 vs. Normal AEP Ohio ($4) ($3) AEP Texas ($7) ($2) Total ($11) ($5) Impact on Operating EPS - Retail Load1 (weather normalized) Q2-26 vs. Q2-25 AEP Ohio 14.9% AEP Texas 10.5% Total 12.9% Impact on Operating EPS2 -$0.06 $0.02 1 Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2 Includes EPS impact of accrued revenues. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”.
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Transmission and Distribution Utilities YTD Performance WEATHER IMPACT NORMALIZED SALES RATE CHANGES 40 Q2 - 2 6 E a r n i n g s P r e s e n t a t i o n Rate Performance, net of offsets ($ in millions) YTD-26 vs. YTD-25 AEP Ohio $36 AEP Texas $24 Total $60 Impact on Operating EPS Weather Impact ($ in millions) YTD-26 vs. YTD-25 YTD-26 vs. Normal AEP Ohio ($19) ($2) AEP Texas ($20) ($1) Total ($39) ($3) Impact on Operating EPS - Retail Load1 (weather normalized) YTD-26 vs. YTD-25 AEP Ohio 17.6% AEP Texas 10.3% Total 14.3% Impact on Operating EPS2$0.09 $0.06 $0.04 1 Includes load on a billed basis only, excludes firm wholesale load and accrued sales. 2 Includes EPS impact of accrued revenues. Operating earnings, operating EPS, adjusted equity and FFO to total debt are non-GAAP measures. Refer to “Non-GAAP Financial Measures”.