AEP Texas Inc.

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Earnings Attributable to AEP Common Shareholders increased from $1 billion in 2025 to $1.2 billion in 2026 primarily due to:

•An increase in sales volumes in the residential class driven by favorable weather in 2026.

•Investment in transmission assets, which resulted in higher revenues and income.

•An increase due to rate proceedings in AEP’s various jurisdictions.

•An increase in sales volume in the commercial and industrial customer classes driven primarily by new data processing load.

•An increase in interest expense due to higher long-term debt balances and higher interest rates.

•A decrease due to a credit to certain existing wholesale generation customers.

Earnings Attributable to AEP Common Shareholders decreased from $3 billion in 2025 to $2.8 billion in 2026 primarily due to:

•The favorable $480 million impact from the receipt of the June 2025 FERC NOLC order related to the treatment of NOLCs in transmission formula rates, partially offset by higher ongoing revenues and income due to continued investment in transmission assets.

•An increase in interest expense due to higher long-term debt balances and higher interest rates.

•A decrease due to a credit to certain existing wholesale generation customers.

•A decrease due to a probable, partial disallowance of the Pirkey Plant net book value in the SWEPCo 2025 Texas Base Rate Case.

•An increase due to rate proceedings in AEP’s various jurisdictions.

•An increase in sales volume in the commercial and industrial customer classes driven primarily by new data processing load.

•A gain from the sale of a non-utility investment in land at APCo.

See Results of Operations section for additional information by segment.

Non-GAAP Financial Measures

AEP reports its financial results in accordance with GAAP. AEP supplements its reporting of financial information with certain non-GAAP financial measures, such as operating earnings. The most comparable GAAP measure to operating earnings is GAAP earnings. Operating earnings, which could differ from earnings reported in accordance with GAAP, 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 below, that management believes are not indicative of AEP’s ongoing performance.

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 information is 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. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures.

Reconciliation of GAAP Earnings to Operating Earnings

The following tables present a reconciliation of operating earnings to the most directly comparable GAAP measure.

(b)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(c)Represents SWEPCo’s agreements with certain existing wholesale customers under generation supply contracts, which resulted in credits to these wholesale customers that were paid in 2026.

(d)Tax effect is calculated using the statutory tax rate unless otherwise noted.

(b)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.

(c)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(d)Represents the reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio.

(b)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(c)Represents the impact of the WVPSC order related to the 2024 Modified Rate Base Cost surcharge update filing.

(d)Represents the estimated impact of the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case.

(e)Represents the estimated impact of the probable, partial disallowance of costs included in AEP Texas’ UTM filing.

(f)Represents SWEPCo’s agreements with certain existing wholesale customers under generation supply contracts, which resulted in credits to these wholesale customers that were paid in 2026.

(g)Tax effect is calculated using the statutory tax rate unless otherwise noted.

(b)Excluding tax related adjustments, all items presented in the table are tax adjusted at the statutory rate unless otherwise noted.

(c)Represents the mark‑to‑market impact of economic hedging activities which are excluded to align with the recognition of the underlying hedged exposures.

(d)Represents an adjustment to the estimated loss on the sale of AEP OnSite Partners as a result of the contractual working capital true-up.

(e)Represents the reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio.

(f)Represents the impact of the FERC NOLC Order for years 2021-2024.

ELECTRIC INDUSTRY TRANSFORMATION

AEP continues to convert large load interest across its service territory into signed customer financial commitments. These commitments, primarily from data processing and other energy-intensive customers, are expected to support sales growth, expand the customer base and improve utilization of AEP’s generation, transmission and distribution systems. New data processing load contributed to commercial and industrial sales growth during 2026, demonstrating that large load additions have begun to contribute to operating results.

To serve committed and forecasted growth, AEP outlined a $100.4 billion, five-year capital plan focused on strengthening transmission infrastructure, adding new generation to support both existing customers and forecasted large load increases and continued improvements in distribution system reliability. Throughout this investment cycle, AEP remains focused on customer affordability and expects to utilize incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms, such as securitizations, to help address affordability.

AEP is leveraging its generation portfolio, transmission network and infrastructure execution capabilities to support committed and forecasted customer demand, including:

•The addition of 1,859 MWs of owned generating capacity in 2026.

•Signing agreements in 2026 to acquire 5,099 MWs in additional generation facilities.

•Requests for proposals seeking approximately 14,400 MWs of generating capacity.

•Capacity purchase agreements to satisfy capacity reserve margins to serve customers.

•Long-term agreements with leading infrastructure services companies to provide engineering, project management and construction support for planned transmission infrastructure expansion.

AEP has advanced large load tariff proposals and modifications across its jurisdictions to facilitate customer interconnections while protecting existing customers. Approved and proposed provisions may include contract periods of up to 20 years, take-or-pay minimums covering 80% to 90% of contracted demand, credit support and customer responsibility for specified infrastructure costs. As of September 30, 2026, AEP filed proposals in eight jurisdictions, with six approved and two pending in Oklahoma and SWEPCo-Texas. AEP continues to engage with regulators, policymakers, RTOs, customers and suppliers to connect large load customers while advancing reliability, resiliency and affordability across its service territory.

PJM Resource Adequacy Reforms

The AEP East Companies are members of PJM. Utilities in PJM can meet their capacity obligations by either: (a) participating in capacity auctions administered by PJM, or (b) via the Fixed Resource Requirement (FRR) alternative in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than OPCo utilize the FRR alternative.

In January 2026, the White House, all thirteen state governors from across the PJM footprint, and senior federal energy officials jointly released a Statement of Principles. This Statement of Principles is designed to increase capacity available in the PJM market for large load customers and to ensure the costs of those resources are paid for by the large load customers to protect existing customer affordability. The Statement of Principles directs PJM to hold a one-time Reliability Backstop Auction, accelerate capacity market reforms in response to unprecedented data center load growth, and align costs associated with new capacity coming into the market with the large load customers necessitating the resources. Subsequently, in a proceeding pending since 2025, the PJM Board of Managers issued a decision letter initiating changes to PJM’s capacity market and interconnection processes.

In July 2026, the PJM Board of Managers approved near-term resource adequacy reforms intended to address projected reliability concerns associated with significant forecasted load growth and capacity shortages. PJM subsequently filed proposals with the FERC in July and August 2026 to establish a Reliability Backstop Procurement (RBP) mechanism and an Interim Resource Adequacy Service (IRAS). The RBP would procure new capacity through long-term commitments, while IRAS would provide for emergency curtailment of certain new large loads not supported by qualifying new capacity. PJM proposed to exclude FRR entities from the RBP procurement targets and associated cost allocation. PJM also proposed to exclude FRR load from the IRAS curtailment service. For new large loads in FRR service areas, PJM instead proposed to cap reliance on existing generation capacity at the quantity owned or contracted before June 1, 2027, with additional capacity needs for those loads to be met through new resources.

In September 2026, the FERC accepted the RBP proposal for filing but suspended its effectiveness until February 28, 2027, subject to refund and further proceedings concerning cost allocation, transmission-owner exit obligations and load-serving entity collateral requirements. To expedite implementation, the FERC encouraged PJM to submit a revised proposal by October 29, 2026. PJM indicated that it intends to submit a revised proposal.

The FERC found PJM’s proposed exclusion of FRR entities from the RBP and associated cost allocation to be just and reasonable. Separately, PJM proposed provisions intended to prevent costs associated with committed RBP resources from being shifted to remaining PJM participants following a transmission owner’s withdrawal. Those provisions could require a withdrawing transmission owner to satisfy certain future obligations on an accelerated basis or arrange for their continued payment. The FERC questioned assigning these obligations to transmission owners rather than the load-serving entities benefiting from the procurement and directed further proceedings on that issue.

In October 2026, the FERC accepted PJM’s definition of Large Load and its Large Load Registry, effective October 12, 2026, and directed a compliance filing within 30 days. The registry covers existing and future large loads, with information-reporting obligations on load-serving entities and supporting information from electric distributors where needed. AEP’s operating companies, including both FRR and non-FRR entities are subject to the Large Load Registry reporting requirement. However, the FERC rejected the remainder of the IRAS filing, including the proposed curtailment framework, Bring Your Own New Capacity requirements and related capacity-market provisions. The FERC identified jurisdictional and other deficiencies and provided guidance for a revised proposal should PJM choose to refile. The IRAS rejection also eliminated the proposed FRR procurement restrictions described above, including the June 1, 2027 cutoff for determining the quantity of existing generation capacity available to serve new large loads.

The ultimate form and timing of additional or revised tariff provisions, and their associated implementation requirements, cost recovery mechanisms and operational impacts, remain uncertain. At this time, AEP cannot predict the outcome of further FERC proceedings or estimate the potential impact, if any, that final approved provisions may have on its financial condition, results of operations or cash flows. AEP will continue to monitor these matters.

Large Load Interconnections in Texas

In June 2025, Texas Senate Bill 6 (SB 6) became effective and was signed into law by the Governor of Texas. SB 6 establishes a standardized process for connecting large load customers within ERCOT in a manner intended to support economic development in Texas while reducing the potential for stranded infrastructure costs. The new legislation establishes criteria for new large load interconnections and directs the PUCT to ensure that these large load customers pay a reasonable share of allocated transmission costs. The PUCT continues its rulemaking efforts to implement SB 6, including provisions related to large load interconnection standards, load forecasting, reliability requirements and transmission cost allocation. The PUCT adopted changes in September 2026, effective October 2026, to the Texas Administrative Code related to Large Load Interconnection Standards. The changes require a large load customer to execute an intermediate agreement, provide certain disclosures and post financial security in the amount of $50,000 per MW before inclusion in an ERCOT interconnection study. The new rule requires a large load customer to execute a standardized interconnection agreement once the allocation of capacity is determined from the ERCOT batch study, provide certain disclosures, and in addition to the financial security, the cash required for the direct interconnection of their load to the broader system. The new rule also establishes the consequences of withdrawing all or a portion of requested or contracted peak demand, establishes the terms for the return of financial security to a large load customer that energizes and requires utilities to segregate cash collateral posted as financial security. In October 2026, AEP Texas segregated approximately $1.2 billion of cash collateral pursuant to the new rule.

AEP Texas has executed Letters of Agreement for approximately 49 gigawatts of incremental load by 2031, including prospective load seeking consideration under ERCOT’s Batch Zero process. ERCOT's Batch Zero process is a one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026 that is designed to evaluate qualifying large load interconnection requests on a system-wide basis, allocate available transmission capacity, identify necessary transmission upgrades and require financial commitments from participating customers. The process applies primarily to large electric loads of 75 MW or greater and serves as the precursor to ERCOT's future recurring batch interconnection framework. In July 2026, AEP Texas received approximately $2 billion of financial security in the form of cash collateral, corporate or parental guarantees and letters of credit for the 45 gigawatts of prospective load seeking consideration for participation in the Batch Zero process through 2032.

In August 2026, the Governor of Texas directed the PUCT and ERCOT to conduct a comprehensive verification of all Batch Zero loads and an audit of data center projects 25 MW and above advancing through ERCOT's interconnection process before any additional projects move forward. Following the governor’s direction, ERCOT announced that it would not meet an August 2026 deadline associated with the Batch Zero interconnection study process and received a good-cause exception from the PUCT regarding Batch Zero schedule and implementation requirements. ERCOT has currently paused Batch Zero classification and study activity and stated it will not authorize large loads to energize until verification is complete.

The recent activities of the PUCT and ERCOT are expected to provide greater clarity regarding large load interconnection requirements, transmission infrastructure needs and the timing and scale of future load growth. Accordingly, the amount, timing and cost responsibility associated with these prospective large load interconnections remain subject to ongoing ERCOT and PUCT actions.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. Through the third quarter of 2026, AEP experienced higher customer demand, driven primarily by new data processing load added in the commercial and industrial customer classes. In addition, AEP experienced higher customer demand in the residential class, due to favorable weather in the third quarter of 2026 compared to the third quarter of 2025. The table below shows the percentage change in sales volume by customer class.

(a)Percentage change for the three months ended September 30, 2026 as compared to the three months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

(b)Percentage change for the nine months ended September 30, 2026 as compared to the nine months ended September 30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

New Generation Resources

The growth of AEP’s regulated generation portfolio reflects the Company’s focus on meeting increasing customer demand for power while balancing cost and reliability.

Acquired Generation Facilities

During 2026, AEP subsidiary companies acquired five generation facilities to support AEP’s portfolio and enhance reliability. These transactions reflect the companies’ continued focus on securing necessary generation to meet future customer demand. See the “Acquisitions” section of Note 6 for additional information. The table below summarizes these acquisitions:

Pending Generation Facilities

In April 2026, I&M entered into a PSA to acquire the Sycamore Riverside Energy Center (Sycamore Plant), a 918 MW natural gas and ultra-low sulfur distillate (dual-fuel)-fired generation facility located in Sullivan County, Indiana. I&M filed an application with the IURC in late April seeking a CPCN for approval of the estimated project costs and associated ratemaking and accounting treatment. A final order from the IURC is expected in December 2026.

In May 2026, APCo filed an application with the Virginia SCC seeking approval for two new solar PSAs including Skycrest (155 MWs) located in Jay County, Indiana, anticipated to be placed in service in December 2028, and Riverstart V (100 MWs) located in Randolph County, Indiana, anticipated to be placed in service in August 2028. The petition also included request for approval of two wind PPA extensions consisting of Beech Ridge (101 MWs) with an 8-year extension starting in 2030 and Camp Grove (150 MWs) with a 10-year extension starting in 2027.

In July 2026, AGR entered into a PSA to acquire the Longview Power Plant, a 710 MW coal-fired generation facility located in Monongalia County, West Virginia. The transaction is subject to customary closing conditions, including approval from the FERC and other required regulatory approvals. The agreement was signed to support growing energy demand in the region and strengthen AEP's ability to provide reliable power at affordable prices. The Company currently expects the acquisition to close in the fourth quarter of 2026 or the first quarter of 2027, although the timing and ultimate completion of the transaction are subject to receiving the required regulatory approvals and other closing conditions.

In July 2026, I&M filed an application for a CPCN with the IURC for approval to construct the Rockport Energy Center, a 1,520 MW combined-cycle natural gas facility to be located in Spencer County, Indiana. In the application, the Company seeks approval of the estimated costs of the project, the authority to recover costs in connection with its development and approval of specific ratemaking and accounting treatment. A final order from the IURC is expected in the first quarter of 2027.

In July 2026, I&M filed an application under its Expedited Generation Resource Plan (EGR Plan) requesting approval of amended contractual terms to the previously approved 245 MW Lake Trout Solar Project PSA. A final order is expected in November 2026.

In September 2026, SWEPCo filed applications for CCNs with the APSC, LPSC and PUCT, seeking regulatory approval for the acquisition of the Brantley Branch project, a 200 MW 6-hour BESS, located in Rusk County, Texas. Regulatory approvals are expected in the third quarter of 2027 and the project is expected to close and come into service in the fourth quarter of 2028.

In October 2026, KPCo entered into an amended agreement with TeraWulf Inc., for 1 GW of contracted demand. KPCo plans to file an application seeking approval of the agreement and the related generation investments in the fourth quarter of 2026.

Significant Approved Generation and Storage Filings

AEP received regulatory approvals from various state regulatory commissions to acquire approximately 2,327 MWsof owned generation and storage facilities, totaling approximately $2.3 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,124 MWs of renewable PPAs. The following table summarizes regulatory approvals received for approved generation projects that are not yet in service as of September 30, 2026:

Significant Generation Requests for Proposal (RFP)

The table below includes active RFPs issued for both owned and purchased power generation. Projects selected will be subject to regulatory approval:

Capacity Purchase Agreements

In addition to the generation projects discussed above, AEP enters into CPAs to satisfy operating companies’ capacity reserve margins to serve customers. The following table includes CPA amounts under contract as of September 30, 2026, by year, for the five-year period 2026-2030:

(a)Seasonal average of volume contracted.

Regulatory Matters - Utility Rates and Rate Proceedings

The Registrants are involved in rate cases and other proceedings with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. Depending on the outcomes, these rate cases and proceedings can have a material impact on results of operations, cash flows and financial condition.

The following tables summarize the completed and pending base rate case proceedings. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

(a)In August 2025, in response to APCo’s and WPCo’s 2024 West Virginia Base Rate Case filing, the WVPSC originally approved a combined $76 million annual increase in base rates based upon a 9.25% ROE. In February 2026, the WVPSC issued an order on reconsideration of the 2024 West Virginia Base Rate Case, approving a revised ROE of 9.75%, resulting in a $15 million prospective annual increase in base rates, to arrive at an authorized annual increase of $91 million effective February 2026.

(b)See “2025 Arkansas Base Rate Case” section of Note 4 in the 2025 Annual Report for additional information.

(c)In March 2026, KPCo filed a request with the KPSC seeking rehearing on the vegetation management finding in the base case order in addition to certain other denied costs. In April 2026, the KPSC issued an order approving KPCo’s request for rehearing.

Pending Base Rate Case Proceedings

Other Significant Regulatory Matters

Piketon Transmission Project (Applies to AEP, AEPTCo and OPCo)

In August 2026, OHTCo, OPCo and an unaffiliated customer executed definitive agreements related to the construction of three 765 kV transmission lines by OHTCo to support the development of a proposed 10.4 GW data center campus in Piketon, Ohio. The three 765 kV transmission lines, each expected to provide approximately 3.2 GWs of incremental transmission capacity, have targeted in-service date goals of December 31, 2028, 2029 and 2030. The initial 800 MWs of load is expected to be served utilizing existing transmission capacity and does not require any additional regulatory approvals.

For the balance of the approximately 10.4 GW, and subject to applicable regulatory approvals and the terms of the definitive agreements, OHTCo is expected to recover approved transmission-related costs related to the new load through arrangements with OPCo, which will, in turn, recover such amounts from the customer pursuant to a retail service agreement designed to prevent any of the costs of the project from being allocated to other OPCo customers. Under the agreement, the customer is responsible for those costs, including the applicable return, with no allocation of those costs to other OPCo customers.

The definitive agreements related to the transmission investment to serve the load provide for a base ROE of 11.35%, which may increase to 11.99% or decrease to 10.71% based on the actual project costs as compared to budgeted costs and actual in-service dates as compared to targeted in-service dates for each transmission line, and include payment terms extending for 20 years following the applicable in-service dates. The agreements establish a budget for the project of approximately $5 billion. The Piketon Transmission Project requires regulatory approvals from PJM, the PUCO and the FERC. The equipment purchase agreement currently in effect requires the customer to fully collateralize OHTCo equipment purchases prior to receiving the required regulatory approvals. The ultimate scope, timing, cost recovery mechanisms and economics of the project are subject to regulatory review and approval.

2025 UTM Filing

In October 2025, AEP Texas submitted its first filing with the PUCT seeking recovery of eligible costs through the UTM. In March 2026, a Texas ALJ issued a PFD recommending partial disallowance of the requested amounts which was based on an interpretation of a later effective date for eligible UTM deferrals. In April 2026, AEP Texas filed responses reflective of the legislative intent of Texas House Bill 5247 (2025). In May 2026, the PUCT Chairman issued a Commissioner Memorandum agreeing with the ALJ’s PFD and ordered the PUCT staff to complete a calculation to confirm the final disallowance amount. Completion of the Commission-required calculation and final order were filed in the third quarter of 2026. In conjunction with the Commissioner Memorandum, AEP Texas recognizedan unfavorable pretax impact of $23 million in May 2026 attributable to a portion of the deferrals included in the UTM application period.

UTM Regulatory Assets

As of September 30, 2026, AEP Texas has deferred, beginning August 2025, approximately $89 million of eligible costs as a regulatory asset for inclusion in future AEP Texas’ UTM applications. AEP Texas has also deferred approximately $34 million related to its system resiliency plan for inclusion in future UTM applications. Investments included in the UTM and the existing capital tracker filings remain subject to prudency review in the utility’s next base rate case proceeding before the PUCT. If any of these deferred costs or investments are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

West Virginia Securitization

In March 2026, the WVPSC issued a financing order approving APCo’s and WPCo’s (the Companies) proposed securitization. In July 2026, the WVPSC approved an overall balance of $2.7 billion of eligible costs for securitization. The Companies are proceeding with the securitization bond issuance process and plan to complete the securitization in the fourth quarter of 2026, subject to market conditions. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

West Virginia Modified Rate Base Cost Surcharge

In April 2026, the WVPSC issued an order that adjudicated the Companies’ 2024 MRBC surcharge update filing. This order affirms previously approved MRBC revenue requirements and allows the Companies to perform a final true-up in an ENEC filing to recover past MRBC costs that were not reflected in MRBC surcharge rates in a timely manner during the four-year existence of the surcharge.

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving a final MRBC true-up without sufficient record support. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss this APCo customer appeal. See the “2026 ENEC Update Filing” and “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” sections of Note 4 for additional information.

West Virginia Inflation-Based Rate Adjustment

In April 2026, the WVPSC issued an order conditionally approving an annual Inflation-Based Rate Adjustment to current base rates of 4% for residential and commercial customers and 2.5% for industrial customers, provided that the Companies: (a) agree with proceeding with securitization, unless otherwise ordered by the WVPSC, (b) agree that the April 2026 Notice of Intent to file a 2026 West Virginia base rate case will be withdrawn and (c) agree that a new base rate case will not be filed prior to June 1, 2027. In April 2026, the Companies agreed to the terms of the Inflation-Based Rate Adjustment described above and filed revised tariff sheets reflecting a $40 million combined annual increase to base rates effective July 1, 2026.

A group of APCo customers submitted an appeal to the WVSC alleging that the WVPSC erred in its April 2026 order approving the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes. In September 2026, APCo and the WVPSC filed motions for the WVSC to dismiss the APCo customer appeal.

An intervening party submitted an appeal to the WVSC regarding the Inflation-Based Rate Adjustment alleging that the WVPSC: (a) failed to carry its burden of proving that the Companies’ existing rates were unreasonable and needed to be changed, (b) failed to adequately support its order with evidence of record and (c) violated the due process rights of the intervening party and the customers that it represents. See the “West Virginia Inflation-Based Rate Adjustment” section of Note 4 for additional information.

If any refund liabilities are imposed related to these West Virginia jurisdictional issues, it would reduce future net income and cash flows and impact financial condition.

Indiana House Enrolled Act 1002

On February 26, 2026, House Enrolled Act 1002 (HEA 1002) was signed into law in Indiana. This law requires Indiana’s investor-owned electricity suppliers to petition the IURC for approval of a multi-year rate plan (MYRP). When establishing an electricity supplier’s authorized return for its MYRP, Indiana law requires the IURC to consider any changes in risk to the electricity supplier and its customers that may result from implementing the MYRP. HEA 1002 also states that performance metrics and performance incentive mechanisms (PIM) will be applicable to each year of the electricity supplier’s MYRP with regards to affordability and service restoration.

In July 2026, the IURC launched two investigations applicable to all Indiana electric suppliers. One investigation considers the risks to the electricity suppliers and customers in Indiana as a result of the electricity supplier implementing an MYRP with respect to an electric suppliers’ authorized return. The second investigation considers the development of guidelines for electric suppliers and stakeholders to utilize in evaluating the future use of trackers under a MYRP framework. In October 2026, the IURC finalized the list of issues for its investigations into ROE and tracker mechanisms with stakeholder testimony due in December 2026 and hearings scheduled for February 2027.

Mitchell Plant Cooling Tower CPCN Requests

In February 2026, WPCo and KPCo filed CPCN and cost recovery requests (Mitchell CPCN) with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to: (a) construct a new mechanical draft cooling tower which would allow for continued operation of the 780 MW Mitchell Plant Unit 2 and (b) recover the related estimated investment of $191 million. WPCo and KPCo each own a 50% undivided interest in Mitchell Plant.

In June 2026, the Department of Energy awarded $51 million to support the WPCo and KPCo Mitchell Plant Cooling Tower investment.

In October 2026, the KPSC issued an order conditionally approving construction and cost recovery through a rider, subject to WVPSC CPCN approval and receipt of funding related to the June 2026 Department of Energy award. In addition, KPCo is required to provide the KPSC with written notice of any increase to estimated project costs that exceeds 5%. Additionally in October 2026, the WVPSC issued an order approving construction. Cost recovery will be addressed in a future filing. WPCo is required to provide the WVPSC with written notice of any increase to estimated project costs that exceeds 10%.

As of September 30, 2026, the net book value of Mitchell Plant Unit 2, before cost of removal and including CWIP and inventory, is estimated to be approximately $639 million ($382 million at WPCo and $257 million at KPCo). If AEP cannot ultimately recover Mitchell Plant Unit 2 costs, it would reduce future net income and cash flows and impact financial condition.

Federal Tax Legislation

In February 2026, the Department of Treasury and the IRS issued additional interim guidance on the application of CAMT, Notice 2026-7. This guidance allows taxpayers to deduct certain tax-deductible repairs when determining adjusted financial statement income for CAMT purposes. This guidance is expected to result in a reduction to applicable Registrants’ prior and future CAMT liabilities.

Additional significant guidance from the Department of Treasury and the IRS is expected on the tax provisions in recently enacted legislation. AEP will continue to monitor any issued guidance and evaluate the impact on AEP’s future net income, cash flows and financial condition.

Fuel Cell Agreements

In 2025, OPCo signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. The PUCO approved the contracts in May 2025. In September 2025, an intervenor filed a request for rehearing with the Supreme Court of Ohio, opposing the PUCO's approval and claiming that the order was unlawful, anti-competitive, and discriminatory. In June 2026, the appeals were dismissed and the PUCO decisions are now final and non-appealable.

In January 2026, an unregulated subsidiary of AEP executed: (a) an unconditional purchase agreement to acquire a substantial portion of its 1 GW option for solid oxide fuel cells for the development and construction of a fuel cell generation facility for approximately $2.65 billion and (b) a 20 year offtake arrangement with a high investment grade third-party customer for 100% of the output of the fuel cell generation facility expected to be located near Cheyenne, Wyoming.

Grid Growth Ventures Investment (Applies to AEP)

In 2026, Transource Energy executed agreements to form Grid Growth Ventures, LLC (Grid Growth Ventures) with First Energy Transmission, LLC to participate in PJM’s 2025 Regional Transmission Expansion Plan (RTEP) competitive process. In February 2026, PJM selected the projects proposed by Grid Growth Ventures to address forecasted reliability and load growth requirements. The RTEP projects awarded by PJM were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $600 million. The RTEP projects awarded by PJM will be developed, owned and operated by Grid Ohio Growth EHV, LLC and Grid Growth Ohio, LLC, subsidiaries of Grid Growth Ventures.

In March 2026, subsidiaries of Grid Growth Ventures, Grid Growth Ohio EHV, LLC and Grid Growth Ohio, LLC, submitted to the FERC a request for acceptance of formula rates for each company, consisting of a formula rate template and implementation protocols, effective May 2026. The filing also requested approval of Federal Power Act Section 219 transmission incentive rate treatments for the projects awarded by PJM to the Grid Growth Ventures subsidiaries. The requested incentive rate treatments include: (a) recovery of abandonment costs if the projects are cancelled for reasons beyond Grid Growth Ventures’ control, (b) inclusion of CWIP in rates while the projects are in development, (c) use of hypothetical capital structure of 40% debt and 60% equity until the earlier of either December 31, 2032 or the date all of the projects are in service, after which Grid Growth Ventures will use its actual capital structure and (d) regulatory asset treatment for pre-commercial costs including carrying charges. The filing also proposed depreciation rates, requested a base ROE of 10.8% for both companies and requested authorization to replicate the formula rate and rate incentive treatments for any subsidiaries of Grid Growth Ventures. In July 2026, the FERC issued an order accepting the formula rate, subject to settlement proceedings which will determine the companies’ base ROE, cost of debt, formula rate template language and depreciation rates.

Midcontinent Grid Solutions Investment (Applies to AEP)

In 2025, Transource Energy and an affiliate of Berkshire Hathaway Energy formed Midcontinent Grid Solutions, LLC to participate in MISO’s 2024 Regional Transmission Expansion Plan competitive process. In January 2026, MISO selected the upgrades proposed by Midcontinent Grid Solutions to address forecasted reliability and load growth requirements. The projects awarded by MISO were estimated to cost approximately $1.2 billion and AEP’s share of this investment was estimated to be $500 million. The projects awarded by MISO will be developed, owned and operated by Midcontinent Grid Solutions Wisconsin, LLC (MGS Wisconsin), a subsidiary of Midcontinent Grid Solutions, LLC.

In September 2025, the FERC issued an order accepting the formula rates requested by Midcontinent Grid Solutions, LLC’s subsidiary, Midcontinent Grid Solutions Iowa, LLC (MGS Iowa), granting its requested effective date of July 2025 and the following: (a) regulatory asset treatment for pre-commercial and formation costs with carrying charges, (b) a hypothetical capital structure of 60% equity and 40% debt through the date of the company’s first transmission project being placed in service, (c) conditional approval of a 50-basis point ROE adder due to participation in an RTO, effective upon the date on which operational control transitions to MISO, and (d) authorization of the company’s request to replicate its formula rate and related treatments for future subsidiaries in MISO. The FERC also accepted MGS Iowa’s proposed use of a 9.98% base ROE, the MISO regional base ROE effective at the time of the FERC order, and the depreciation rates proposed by the company.

As an affiliate of MGS Iowa, MGS Wisconsin is authorized to replicate MGS Iowa’s FERC-approved formula rate. A request was filed in April 2026 and included an additional incentive for the recovery of abandonment costs if the projects are cancelled for reasons beyond MGS Wisconsin’s control. In June 2026, the FERC approved MGS Wisconsin’s request.

NOLCs in Retail Jurisdictions - IRS PLRs

AEP’s utility subsidiaries have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail ratemaking. In April 2024, supportive PLRs for certain retail jurisdictions were received from the IRS, effective March 2024. The PLRs concluded NOLCs on a stand-alone ratemaking basis should be included in rate base and in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As of September 30, 2026, there were four jurisdictions awaiting approval and two jurisdictions that have been approved but are subject to refund in their status of transitioning to stand-alone treatment of NOLCs in retail ratemaking. Beginning in the second quarter of 2024 and continuing until the NOLC revenue requirement is in rates, AEP is recognizing additional regulatory assets related to revenue requirement amounts to be collected from customers. As of September 30, 2026, AEP had NOLC regulatory assets of $92 million, of which $83 million are classified as pending final regulatory approval and $9 million are classified as approved for recovery.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies for additional information.

Claims for Indemnification Made by Owners of the Gavin Power Station

AEP sold the Gavin Power Station to Gavin Power LLC and Lighthouse Generation LLC in 2017. Pursuant to the PSA for that transaction, AEP maintained responsibility to complete closure of the 300 acre unlined fly ash reservoir (FAR) pond in accordance with the closure plan approved by the Ohio Environmental Protection Agency and to indemnify the purchasers for that work. In November 2022, the Federal EPA made several assertions related to the CCR Rule (see “CCR Rule” section below for additional information), including an assertion that the closure of the FAR is noncompliant with the CCR Rule in multiple respects. The owners of the Gavin Power Station have notified AEP that they believe they are entitled to indemnification for any damages that may result from these claims. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. See “Claims for Indemnifications Made by Owners of the Gavin Power Station” section of Note 5 for additional information.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and potential future requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges. AEP is unable to predict changes in regulations, regulatory guidance, legal interpretations, policy positions and implementation actions that may evolve.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. Management is engaged in the development of possible future requirements including the items discussed below.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Impact of Environmental Compliance on the Generating Fleet

The rules and environmental control requirements discussed below will have a material impact on AEP’s operations. As of September 30, 2026, AEP owned generating capacity of approximately 27,200 MWs, of which approximately 10,200 MWs were coal-fired. In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Since then, the Federal EPA has finalized actions revising or repealing portions of certain 2024 rules and has proposed additional revisions or repeals. Most recently, in September 2026, the Federal EPA finalized a partial repeal of the 2024 greenhouse gas standards for fossil fuel-fired electric generating units and concurrently proposed rescinding the remaining power-sector greenhouse gas findings and standards under Clean Air Act Section 111. Management continues to evaluate the impacts of the rules that are currently in effect on the plans for the future of AEP’s generating fleet, in particular, the economic feasibility of making the requisite environmental investments in AEP’s fossil generation fleet. AEP continues to refine the cost estimates of complying with these rules to identify the best alternative for promoting compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.

The regulatory requirements and associated costs of compliance may also change based on: (a) potential state rules that impose additional more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) regulatory and policy changes implemented by the President and the Federal EPA and (h) other factors.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states and localities implement and administer many of these programs and could impose additional or more stringent requirements. Primary CAA regulatory programs that continue to drive investments in AEP’s existing generating units include the following: (a) periodic revisions to NAAQS and the development of SIPs to achieve more stringent standards, (b) implementation of the regional haze program by the states and the Federal EPA, (c) regulation of hazardous air pollutant emissions under MATS, (d) implementation and review of CSAPR and (e) the Federal EPA’s regulation of GHG emissions from fossil generation under Section 111 of the CAA. Certain notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

National Ambient Air Quality Standards

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA, which in turn may require AEP to make investments in pollution control equipment at existing generating units or change how units are dispatched and operated. In February 2024, the Federal EPA finalized a new more stringent annual primary PM2.5 standard.

Areas with air quality that does not meet the new standard will be designated by the Federal EPA as “nonattainment,” which will trigger an obligation for states to revise their SIPs. In November 2025, in connection with pending litigation challenging the new standards, the Federal EPA filed a motion asking the court to vacate the stricter PM2.5 standard. In June 2026, the United States Court of Appeals for the District of Columbia Circuit denied the request. In a separate case, in July 2026, the United States District Court for the Northern District of California ordered the Federal EPA to complete area designations under the Agency’s revised annual fine particulate matter (PM2.5) NAAQS by February 2027. In September 2026, the Federal EPA appealed the district court’s order to the United States Court of Appeals for the Ninth Circuit. The agency requested, and the Ninth Circuit granted, expedited consideration of the case. However, while the appeals are pending, the Federal EPA is taking the actions required under the CAA to meet the court’s February 2027 deadline. In October 2026, the Federal EPA issued notices to states, territories, and tribes describing its intended designation approach and requested additional information within 30 days. In October 2026, the Federal EPA also joined a broad coalition of states and associations in petitioning the United States Supreme Court to review the 2024 standard.

If the rule is not vacated by any further legal challenge, states must revise SIPs to attain the new standard. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require additional pollution controls or the implementation of operational constraints. At this time, management cannot reasonably estimate any impacts on AEP’s operations, cash flows, net income or financial condition.

Regional Haze

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which would require certain power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. The rules implementing the Regional Haze requirements of the CAA have been revisited over time. In January 2026, the Federal EPA published a final rule extending the due date for the next round of Regional Haze SIP submittals by states to July 31, 2031.

The Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO 2 emissions trading program based on CSAPR allowance allocations. Environmental groups filed challenges to these various rulemakings in district courts in the Fifth Circuit and the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and intervened in the Fifth Circuit litigation in support of the Federal EPA. In July 2024, the United States District Court for the District of Columbia Circuit entered a consent decree setting deadlines for the Federal EPA to rule on Regional Haze SIPs for 32 states, including Texas. In September 2024, the Federal EPA signed a proposed rule to partially approve and partially disapprove the Texas SIP revision. In May 2025, the Federal EPA proposed to withdraw the prior proposed rule, including the proposed partial disapproval of the Texas SIP revision, and instead proposed to approve the Texas Regional Haze SIP. In December 2025, the Federal EPA finalized its approval of the Texas and Oklahoma SIPs. The Federal EPA has recently approved Regional Haze SIP submissions for Ohio and West Virginia, both of which have been appealed by environmental groups. In February 2026, the Federal EPA proposed to approve the Regional Haze SIP for Oklahoma’s second implementation period. In August 2026, the Federal EPA proposed approval of an Oklahoma SIP revision submitted in March 2026 for the first implementation period, revising source-specific Regional Haze requirements applicable to Northeastern Power Station. Management will continue to monitor the rulemakings and litigation and cannot predict the outcome.

New Source Performance Standards

In January 2026, the Federal EPA finalized revisions to the New Source Performance Standards for stationary combustion turbine units that commenced construction, modification or reconstruction after December 13, 2024. The new standards for NOX require a level of performance equivalent to the application of selective catalytic reduction for large, high-utilization natural gas-fired turbines, but establish various levels of combustion controls as the best system of emission reductions for smaller and lower-utilization turbines. The rule does not change the SO 2 limits applicable to combustion turbines. Management is evaluating the implications of the rule on new combustion turbine projects. Several environmental groups have challenged the rule and in April 2026, AEP and other utilities moved to intervene in support of the Federal EPA in that litigation.

Cross-State Air Pollution Rule

CSAPR is a regional trading program that the Federal EPA began implementing in 2015 to address interstate transport of emissions that contribute significantly to nonattainment and interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 2006 PM2.5 NAAQS in downwind states. CSAPR relies on SO 2 and NOX allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted basis. The Federal EPA has revised, or updated, the CSAPR trading programs several times since they were established.

In February 2023, the Federal EPA Administrator finalized the disapproval of interstate transport SIPs submitted by 19 states, including Texas, addressing the 2015 Ozone NAAQS. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR ozone season program in states to which the FIP applies. The FIP was the subject of judicial review in the United States Court of Appeals for the District of Columbia Circuit and has since been administratively stayed pending the Supreme Court lifting its June 2024 order staying enforcement of the Good Neighbor Plan, other courts lifting judicial orders staying the Federal EPA SIP disapproval actions as to SIPs submitted by several states, and the Federal EPA taking subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in April 2025, the court placed the challenges to the Good Neighbor Plan in abeyance pending further order of the court. The Federal EPA has indicated it intends to propose rulemaking to revise the rule. Management will continue to monitor the litigation and any further actions by the Federal EPA for any potential impact to operations.

Climate Change, CO 2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new GHG standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO 2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO 2 emissions from new gas turbines. The rule also offers early retirement of coal plants in lieu of carbon capture and storage as an alternative means of compliance.

Twenty-seven states, numerous companies, trade associations and others challenged the rule. AEP has joined with several other utilities to challenge the rule and has asked the court to stay the rule during the litigation, and the appeals have been consolidated. The court stayed the litigation pending rulemaking by the Federal EPA. In June 2025, the Federal EPA proposed to repeal the GHG emissions standards for fossil-fueled fired electric generating units based on a determination that GHG emissions from power plants do not significantly contribute to air pollution that may endanger public health or the environment. As an alternative, the Federal EPA proposed to eliminate GHG standards for existing coal and gas units and to keep only certain emission limits applicable to new sources. These proposals have not been finalized. In September 2026, the Federal EPA finalized a partial repeal of the 2024 standards, including the emission guidelines for existing fossil fuel-fired steam generating units, the carbon capture and sequestration-based standards for coal-fired steam generating units undertaking a large modification, and the Phase 2 carbon capture and sequestration-based standards for new base-load stationary combustion turbines. Concurrently, the Federal EPA issued a supplemental proposal to rescind the remaining greenhouse gas findings and standards for fossil fuel-fired power plants under Clean Air Act Section 111. Management is evaluating the final rule and supplemental proposal, including their effects on compliance planning, generation strategy and the pending litigation. The final rule will become effective 60 days after publication in the Federal Register. Management cannot predict the outcome of the supplemental proposal or related litigation. Future changes to greenhouse gas requirements could affect the timing and economics of investments in AEP's fossil generation fleet. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

AEP is committed to delivering reliable, affordable power and routinely submits IRPs in various regulatory jurisdictions to address future generation needs. Accordingly, AEP continues to focus on developing energy solutions that align with state and federal policy objectives, customer expectations, and reliability requirements. These energy solutions may include a range of generation and energy resources, depending on the needs and priorities of the jurisdictions. AEP remains committed to evaluating and pursuing generation strategies that support reliability, affordability and long-term energy needs where supported by regulators and customers. As an example, APCo and I&M are seeking early site permits to bring small modular reactors to Virginia and Indiana as part of their evaluation of future generation options. AEP’s performance will ultimately be driven by the needs and desires of the jurisdictions AEP serves and the company will continue to engage with regulators and policymakers to meet the energy needs while facilitating the delivery of reliable, affordable energy.

MATS Rule

In April 2024, the Federal EPA issued a revised MATS rule for power plants, which includes a more stringent standard for emissions of filterable PM for coal-fired electric generating units, as well as a new mercury standard for lignite-fired electric generating units. The rule also requires the installation and operation of continuous emissions monitors for PM. Several states and other parties have challenged the rule in the United States Court of Appeals for the District of Columbia Circuit, but management cannot predict the outcome of the litigation. The litigation is being held in abeyance. In February 2026, the Federal EPA finalized its repeal of the 2024 MATS rule, and the rule’s requirements reverted to the 2012 MATS rule emission standards. That repeal has been challenged by various groups. Management will continue to monitor the litigation but does not anticipate any challenges complying with the standards in the now-repealed 2024 rule should its repeal be reversed by the court.

CCR Rule

The Federal EPA’s CCR Rule regulates the disposal and beneficial use of CCR, including fly ash and bottom ash created from coal-fired generating units and FGD gypsum generated at some coal-fired plants. As originally promulgated in 2015, the rule applied to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers.

In August 2018, the District of Columbia Circuit Court vacated and remanded certain aspects of the 2015 CCR rule, including an exemption for legacy impoundments. Following this, the Federal EPA issued a final rule in August 2020, setting an April 11, 2021 deadline for unlined CCR impoundments to cease waste acceptance and commence closure. This rule permits a facility to request a deadline extension from the Federal EPA if alternative disposal capacity is unavailable or a compliant conversion or a plant retirement is in progress.

In January 2022, the Federal EPA made public statements in the context of a deadline extension request submitted by the Gavin Power Station suggesting more stringent closure requirements for CCR units. See “Claims for Indemnification Made by Owners of the Gavin Power Station” above for additional information. In April 2022, a petition was filed with the District of Columbia Circuit Court of Appeals, arguing that the Federal EPA could not enforce these new purported requirements without proper rulemaking. In June 2024, the District of Columbia Circuit Court dismissed these petitions, finding the statements were not amendments to existing regulations and thus the court lacked jurisdiction.

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). That rule has been challenged in the District of Columbia Circuit Court. In the second quarter of 2024, AEP evaluated the applicability of the rule to current and former plant sites and recorded a $674 million increase in ARO, based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the Legacy CCR Rule. In March 2025, the Federal EPA announced plans to make changes to the CCR Rule and to work with states to implement future CCR requirements. As a result, the litigation challenging the 2024 Legacy Rule is being held in abeyance. In November 2025, the Federal EPA proposed to extend by three years the compliance deadline applicable to certain facilities operating pursuant to alternative closure deadlines for unlined surface impoundments greater than 40 acres. In February 2026, the Federal EPA finalized a rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. Additionally, this rule makes conforming changes to the remaining CCR management units compliance deadlines. In April 2026, the Federal EPA proposed revisions to the CCR Rule that would rescind requirements for CCR management units, revise requirements for beneficial use of CCR materials, allow expanded reliance on state-approved and other regulatory closures of legacy units, and introduce a new, permit-based, site-specific compliance pathway. In July 2026, the Federal EPA issued an advance notice of proposed rulemaking regarding the Federal CCR Permit Program. The Federal EPA is evaluating whether a general permit structure could support the site-specific compliance pathways proposed in April 2026. Management is evaluating the proposal and has participated in the rulemaking process.

Should additional corrective measures like groundwater treatment or ash removal be mandated at any of AEP’s coal-fired facilities, AEP could face substantial costs that could materially and adversely affect financial condition, results of operations and cash flows. See “Federal EPA’s Revised CCR Rule” section in Note 5 for additional information.

Clean Water Act Regulations

The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. A revision to the ELG rule, published in October 2020, established additional options for reusing and discharging small volumes of bottom ash transport water, provided an exception for retiring units and extended the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water. For affected facilities required to install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain.

In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025 to retire by 2034. Several petitions for review have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo also challenged the rule by filing a joint petition with a utility trade association in which AEP participates. The litigation challenging the ELG Rule is being held in abeyance while the new administration evaluates the rule. The Federal EPA has announced plans to reconsider the standards and deadlines established by the 2024 ELG rule.

In December 2025, the Federal EPA issued the Deadline Extension ELG Rule to extend the compliance deadlines in the 2024 ELG Rule by five years as well as to establish a site-specific mechanism for extending compliance deadlines for both the 2020 and 2024 ELG Rules. The Deadline Extension ELG Rule also extended the deadline to commit to cease coal combustion by 2034 from December 31, 2025 to December 31, 2031. Several environmental organizations filed petitions for review challenging the Federal EPA's December 2025 ELG Deadline Extension Rule. Those challenges were consolidated in the United States Court of Appeals for the Second Circuit, where the litigation remains pending. Management is evaluating the compliance alternatives in the ELG rule, taking into consideration the requirements of other rules and their combined impacts to operations. Management cannot predict the outcome of the pending litigation or any further rulemaking actions by the Federal EPA related to the ELG rule.

In January 2026, the Federal EPA proposed a rule titled Updating the Water Quality Certification Regulations. Through the proposed rule, the Federal EPA is attempting to clarify the Clean Water Act section 401 certification process for states and tribes. Under section 401, a federal agency cannot conduct any activity that may result in a discharge into waters of the United States without obtaining a permit from a State or authorized tribe in the location of the discharge certifying compliance with applicable water quality requirements. The proposed rule aims to reduce regulatory delays associated with the certification process. Management will monitor the rulemaking for any potential impacts to operations.

The definition of “waters of the United States” has been subject to rulemaking and litigation which has led to inconsistent scope among the states. In November 2025, the Federal EPA and the United States Army Corps of Engineers proposed a revised definition of “waters of the United States” to conform to a decision by the United States Supreme Court. In September 2026, the agencies issued a supplemental notice of proposed rulemaking seeking additional public comment on alternative approaches prior to issuing a final rule. The rulemaking remains pending. Management will continue to monitor developments in rulemaking and litigation for any potential impact to operations.

Impact of Environmental Regulation on Coal-Fired Generation

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management regularly evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

For generating facilities retired or planned for retirement in advance of the retirement date currently authorized for ratemaking purposes, with related accelerated depreciation regulatory assets pending regulatory approval, the table below summarizes the net book value and related regulatory asset balances recorded as of September 30, 2026:

(a)Net book value, including CWIP, excluding cost of removal and materials and supplies.

(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. In April 2025, PSO and the ODEQ finalized a second amended regional haze agreement that would allow continued operation of the Northeastern Plant, Unit 3, on natural gas, through May 31, 2041. This agreement is contingent upon approval by the Federal EPA in the form of a revised SIP, which the ODEQ has submitted. Federal EPA proposed to approve the revised Oklahoma SIP in August 2026. That proposal remains pending. In anticipation of approval from the Federal EPA, PSO began operating Northeastern Plant, Unit 3 on natural gas in January 2026.

(d)Represents Texas jurisdictional share.

(e)SWEPCo requested recovery of the Texas jurisdictional share of the remaining net book value of the Pirkey Plant in its 2025 Texas Base Rate Case. See the “Regulated Generating Unit that has been Retired and Related Fuel Operations” section of Note 4 for additional information. In January 2026, the FERC issued an order providing recovery of the Pirkey Plant based on blended recovery periods determined by all SWEPCo jurisdictions including Texas.

(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively. In February 2026, the APSC issued an order approving the application for a CCN. Additionally, in September and October 2026, the PUCT and the LPSC, respectively, issued orders approving the stipulation and settlement agreements related to the CCN applications.

(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

AEP’s Reportable Segments

AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight applicable to each public utility subsidiary. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments are as follows:

•Vertically Integrated Utilities

•Transmission and Distribution Utilities

•AEP Transmission Holdco

•Generation & Marketing

The remainder of AEP’s activities are presented as Corporate and Other, which is not considered a reportable segment. See Note 8 - Business Segments for additional information on AEP’s segments.

The following discussion of AEP’s results of operations by segment provides a comparison of Earnings (Loss) Attributable to AEP Common Shareholders for the three months ended and nine months ended September 30, 2026 as compared to the three months ended and nine months ended September 30, 2025. For AEP’s Vertically Integrated Utilities and Transmission and Distribution Utilities segments and Registrant Subsidiaries within these segments, the results include revenues from rate rider mechanisms designed to recover fuel, purchased power and other recoverable expenses such that the revenues and expenses associated with these items generally offset and do not affect Earnings Attributable to AEP Common Shareholders. For additional information regarding the financial results for the three and nine months ended September 30, 2026 and 2025, see the discussions of Results of Operations by Registrant Subsidiary.

A detailed discussion of AEP’s 2025 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations section included in the 2025 Annual Report.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:

See Note 8 - Business Segments for additional information on Earnings (Loss) Attributable to AEP Common Shareholders by segment.

Heating Degree Days and Cooling Degree Days

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the Eastern Region have a larger effect on revenues than changes in the Western Region due to the relative size of the two regions and the number of customers within each region.

The actual heating degree days are calculated on a 55-degree temperature base and the actual cooling degree days are calculated on a 65-degree temperature base for Registrant Subsidiaries except AEP Texas. AEP Texas’ actual heating degree days are calculated on a 55-degree temperature base and actual cooling degree days are calculated on a 70-degree temperature base.

VERTICALLY INTEGRATED UTILITIES

Summary of KWh Energy Sales for Vertically Integrated Utilities

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

•Retail Revenues increased $408 million primarily due to the following:

•A $261 million increase in base rate and rider revenues.

•A $99 million increase in weather-related usage primarily in the residential class driven by a 24% increase in cooling degree days primarily in the western region.

•A $45 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•An $18 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $5 million primarily due to Rockport Plant, Unit 2 merchant sales, economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $1 million primarily due to the following:

• A $15 million increase due to continued transmission investment.

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by an equal amount of incremental SPP upgrade costs in Other Operation and Maintenance expenses.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $47 million primarily due to decreases at APCo and PSO, partially offset by increases at I&M and SWEPCo.

•Other Operation and Maintenance expenses increased $120 million primarily due to the following:

•A $63 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $32 million increase in employee-related costs.

•A $30 million increase in storm expenses.

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Depreciation and Amortization expenses increased $112 million primarily due to the following:

•A $79 million increase due to a higher depreciable base at I&M and PSO.

•A $28 million increase at APCo primarily due to a July 2026 order approving a final true-up to recover past West Virginia MRBC costs.

•A $5 million decrease at I&M due to Michigan PTC deferral activity.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher AFUDC base and higher equity return rates at I&M and PSO.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $7 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $61 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $45 million primarily due to the following:

•A $42 million decrease due to a decrease in PTCs.

•A $35 million decrease due to an increase in pretax book income.

•A $16 million increase due to a decrease in flow-through expense.

•A $12 million increase due to a decrease in state taxes.

•A $7 million increase due to a decrease in flow-through CAMT expense.

•Retail Revenues increased $759 million primarily due to the following:

•A $632 million increase in base rate and rider revenues.

•A $157 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•A $72 million increase in weather-related usage primarily in the residential class driven by a 19% increase in cooling degree days primarily in the western region.

•A $107 million decrease in fuel revenues primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•A $41 million decrease at SWEPCo due to a credit to certain existing wholesale generation customers.

•Off-system Sales increased $52 million primarily due to Rockport Plant, Unit 2 merchant sales during Winter Storm Fern in January 2026, partially offset by a decrease in merchant sales and economic hedging activity at I&M and margins in July 2026 attributable to increased PJM prices at APCo.

•Transmission Revenues increased $13 million primarily due to the following:

•A $78 million increase due to continued transmission investment.

•A $56 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $12 million decrease due to the repayment of SPP upgrade credits, offset by lower SPP upgrade costs in Other Operation and Maintenance expenses.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $68 million primarily due to decreases at APCo, PSO and SWEPCo, partially offset by an increase at I&M.

•Other Operation and Maintenance expenses increased $327 million primarily due to the following:

•A $137 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $63 million increase in employee-related costs.

•A $62 million increase in storm expenses.

•A $29 million increase in vegetation management costs.

•An $11 million increase in distribution-related expenses driven by system improvements, reliability programs, meters and transformers, customer driven third-party work and amortization of storm-related regulatory assets.

•A $24 million decrease due to the refund of SPP upgrade costs at PSO and SWEPCo.

•Asset Impairments and Other Related Charges increased $31 million due to the probable, partial disallowance of the Pirkey Plant net book value in the 2025 Texas Base Rate Case at SWEPCo.

•Depreciation and Amortization expenses increased $193 million primarily due to the following:

•A $145 million increase primarily due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $26 million increase at APCo primarily due to the cumulative regulatory deferral true-up for the impact of CAMT expense incurred related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $8 million increase due to NOLC-related Excess ADIT deferrals recorded in 2025 and the amortization of these deferrals recorded in 2026 for IURC approved recovery through I&M’s Indiana tax rider.

•An $11 million decrease at I&M due to Michigan PTC deferral activity.

•A $5 million decrease at SWEPCo primarily due to higher over-recovery of costs and allowable returns associated with generation rider recovery.

•Taxes Other Than Income Taxes increased $35 million primarily due to the following:

•A $21 million increase in property taxes at APCo, PSO and SWEPCo.

•A $7 million increase due to higher business and occupation taxes at APCo.

•Allowance for Equity Funds Used During Construction increased $17 million primarily due to a higher AFUDC base and higher equity return rates primarily at I&M, KPCo and SWEPCo.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $19 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $168 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $25 million primarily due to the following:

•A $114 million decrease due to a reduction in Excess ADIT primarily due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $28 million decrease due to an increase in pretax book income.

•A $70 million increase due to an increase in PTCs.

•A $31 million increase due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•A $12 million increase due to a decrease in state taxes.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

(b)Primarily Ohio’s contractually obligated purchases of OVEC power sold to PJM.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities

•Retail Revenues increased $210 million primarily due to the following:

•A $141 million increase in rider revenues in Ohio and Texas.

•A $40 million increasedue to higher prices for purchased power to serve OPCo’s SSO customers.

•A $19 million increase in weather-related usage primarily due to an 18% increase in cooling degree days in Texas and an 8% increase in cooling degree days in Ohio.

•A $10 million increase in weather-normalized revenues primarily in the commercial and industrial classes in Ohio.

•Off-system Sales decreased $32 million primarilydue to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•Transmission Revenues increased $14 million primarily due to continued transmission investment in Ohio and Texas.

•Other Revenues decreased $14 million primarily due to the following:

•An $8 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenues as a result of approved legislation in Ohio in May 2025, which ended the retail recovery of OVEC purchased power costs.

•A $5 million decrease primarily due to a reduction in the PUCT authorized cap on Texas energy efficiency utility incentives.

•Purchased Electricity for Resale expenses decreased $14 million primarily due to the following:

•A $34 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $8 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•A $2 million decrease in recoverable alternative energy rider expenses.

•A $36 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates increased $8 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $141 million primarily due to the following:

•An $86 million increase primarily due to an increase in recoverable PJM transmission expenses in Ohio.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $14 million increase in distribution expenses primarily related to recoverable storm restoration costs and recoverable vegetation management expenses in Ohio.

•A $7 million increase due to recoverable Transmission Cost Recovery Factor expenses in Texas.

•A $7 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•Depreciation and Amortization expenses increased $21 million primarily due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased$11 million primarily due to higher property taxes in Ohio.

•Allowance for Equity Funds Used During Construction increased $12 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $12 million primarily due to the following:

•A $14 million increase due to higher long-term debt balances in Texas.

•A $10 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

•A $6 million decrease due to an increase in the debt component of AFUDC in Texas.

•A $5 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $6 million primarily due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•Retail Revenues increased $345 million primarily due to the following:

•A $232 million increase in rider revenues in Ohio and Texas.

•A $99 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $33 million increase in weather-normalized revenues primarily in the residential and commercial classes in Ohio and Texas.

•A $20 million decrease in weather-related usage primarily driven by a 4% decrease in heating degree days in Ohio and less extreme weather conditions in the first six months of 2026 compared to the same period in 2025 in Texas.

•Off-system Sales decreased $13 million primarily due to the following:

•A $32 million decrease due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•An $18 million increase due to increased sales of OPCo’s OVEC purchased power in the first half of 2026 driven by higher market prices and volumes.

•Transmission Revenues increased $66 million primarily due to continued transmission investment in Ohio and Texas.

•Purchased Electricity for Resale expenses decreased $27 million primarily due to the following:

•A $57 million decrease in OVEC purchased power costs due to the transfer of OPCo’s OVEC power participation entitlement to AGR in June 2026.

•A $52 million decrease as a result of legislation approved in Ohio in 2025 related to the elimination of OPCo’s ability to recover from, or refund to, customers the difference between purchased power expenses from OVEC and OVEC-related revenues from PJM.

•An $86 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates expenses increased $13 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $258 million primarily due to the following:

•A $151 million increase in transmission expenses primarily due to a $134 million increase in recoverable PJM transmission expenses and a $12 million increase in recoverable vegetation management expenses in Ohio.

•A $28 million increase in distribution expenses primarily related to recoverable vegetation management expenses and recoverable storm restoration costs in Ohio.

•A $22 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•An $18 million increasedue to the partial disallowance of regulatory assets associated with the UTM deferrals in Texas.

•A $14 million increase in transmission and distribution expenses in Texas.

•A $13 million increase in administrative and general expenses primarily due to employee-related expenses in Texas.

•Depreciation and Amortization expenses increased $44 million due to a higher depreciable base in Ohio and Texas.

•Taxes Other Than Income Taxes increased $37 million due to the following:

•A $25 million increase due to higher property taxes in Ohio.

•An $8 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $27 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $23 million primarily due to the following:

•A $38 million increase due to higher long-term debt balances in Texas.

•An $11 million increase due to interest on customer deposits in Texas from ERCOT’s Batch Zero process.

•A $15 million decrease due to an increase in the debt component of AFUDC in Texas.

•An $11 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $14 million primarily due to the following:

•A $23 million decrease due to an increase in Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•A $5 million decrease due to an increase in AFUDC equity.

•An $16 million increase due to an increase in pretax book income in Ohio.

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

The major component of the increase in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

•Transmission Revenues increased $42 million primarily due to continued transmission investment.

Expenses and Other and Income Tax Expense:

•Other Operation and Maintenance expenses increased $12 million primarily due to the following:

•A $6 million increase in employee-related costs.

•A $2 million increase in vegetation management and facility compliance costs.

•A $2 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $12 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes decreased $10 million primarily due to prior period adjustments in Ohio, partially offset by higher property taxes associated with increased transmission investment.

•Allowance for Equity Funds Used During Construction increased $5 million primarily due to a higher CWIP base.

•Interest Expense increased $8 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

The major components of the decrease in Transmission Revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:

•Transmission Revenues decreased $49 million primarily due to the following:

•A $214 million decrease due to the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $161 million increase due to continued transmission investment.

Expenses and Other, Income Tax Expense, Equity Earnings of Unconsolidated Subsidiaries and Net Income Attributable to Noncontrolling Interest changed between years as follows:

•Other Operation and Maintenance expenses increased $39 million primarily due to the following:

•A $16 million increase in employee-related costs.

•A $12 million increase in vegetation management and facility compliance costs.

•A $7 million increase in affiliated rent and shared services.

•Depreciation and Amortization expenses increased $36 million due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $14 million primarily due to higher property taxes associated with increased transmission investment, partially offset by prior period adjustments in Ohio.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher CWIP base and higher equity rates.

•Interest Expense increased $29 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $210 million primarily due to the following:

•A $254 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $31 million decrease due to a decrease in pretax book income.

•A $5 million decrease due to a decrease in state taxes.

•Equity Earnings of Unconsolidated Subsidiaries increased $7 million primarily due to higher pretax earnings at ETT.

•Net Income Attributable to Noncontrolling Interests increased $2 million primarily due to the following:

•A $56 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

•A $54 million decrease due to higher 2025 earnings for Midwest Transmission Holdings due to the impact of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

GENERATION & MARKETING

•Retail, Trading and Marketing increased $116 million primarily due to higher market prices in 2026.

•Merchant Generation increased $64 million primarily due to higher realized prices in 2026.

•Other Revenues increased $58 million primarily due to continued progress on customer infrastructure projects in 2026.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $167 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses increased $13 million primarily due to continued progress on customer infrastructure projects in 2026, partially offset by renewable contract modification proceeds.

•Interest and Investment Income increased $5 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

•Retail, Trading and Marketing increased $384 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $108 million primarily due to higher realized prices in 2026.

•Other Revenues increased $94 million primarily due to continued progress on customer infrastructure projects in 2026.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $533 million primarily due to an increase in energy costs in 2026.

•Interest and Investment Income increased $14 million primarily due to an increase in interest income due to higher advances to affiliates.

•Income Tax Expense increased $7 million primarily due to an increase in pretax book income.

CORPORATE AND OTHER

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $118 million in 2025 to a loss of $109 million in 2026 primarily due to:

•A $71 million increase in Income Tax Benefit primarily due to the following:

•A $44 million increase due to an increase in PTCs.

•A $10 million increase due to a decrease in pretax book income.

•A $9 million increase due to a decrease in state taxes.

This increase in earnings was partially offset by:

•A $36 million increase in interest expense primarily due to higher long-term debt balances.

•A $12 million increase in employee-related costs.

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $215 million in 2025 to a loss of $333 million in 2026 primarily due to:

•A $74 million increase in interest expense primarily due to higher long-term debt balances.

•A $12 million increase in employee-related costs.

•An $11 million decrease in the recognition of deferred revenues on completed contracts.

These decreases in earnings were partially offset by:

•A $20 million increase in Income Tax Benefit primarily due to the following:

•A $26 million increase due to a decrease in pretax book income.

•A $7 million increase due to an increase in PTCs.

•A $17 million decrease due to an increase in state taxes.

AEP CONSOLIDATED INCOME TAXES

Income Tax Expense decreased $14 million primarily due to:

•A $22 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $21 million decrease due to a decrease in state taxes.

•A $7 million decreasedue to a decrease in flow-through CAMT expense.

•A $4 million decrease due to an increase in excess ADIT asset reversals.

•A $2 million decrease due to an increase in PTCs.

•A $46 million increase due to an increase in pretax book income.

Income Tax Expense increased $208 million primarily due to:

•A $368 million increase due to a reduction in Excess ADIT as a result of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.

•A $76 million decrease due to an increase in PTCs.

•A $31 million decrease due to the cumulative true-up of CAMT related to IRS Notice 2026-07 allowing tax repair deductions in the calculation of CAMT.

•An $18 million decrease due to an increase in amortization of Excess ADIT.

•A $13 million decrease due to an increase in flow-through benefits primarily driven by AFUDC equity.

•A $13 million decrease due to favorable discrete adjustments.

FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

AEP’s ratio of debt-to-total capital increased from 60.3% to 61.5% as of December 31, 2025 and September 30, 2026, respectively, primarily due to an increase in long-term debt to support AEP’s capital investment plan in addition to working capital needs.

Liquidity

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity for the next twelve months and for the foreseeable future. As of September 30, 2026, AEP had $8 billion of revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that there is an increase in interest rates, it could reduce future net income and cash flows and impact financial condition. In addition, market volatility and reduced liquidity in the financial markets could affect AEP’s ability to raise capital on reasonable terms to fund capital needs, including construction costs and refinancing maturing indebtedness.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2026, available liquidity was approximately $7.4 billion as illustrated in the table below:

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first nine months of 2026 was $2.1 billion. The weighted-average interest rate for AEP’s commercial paper for the nine months ended September 30, 2026 was 3.94%.

Other Credit Facilities

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under seven uncommitted facilities totaling $850 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 2026 was $525 million with maturities ranging from October 2026 to September 2027.

Securitized Accounts Receivables

AEP Credit’s receivables securitization agreement provides a commitment of $900 million from bank conduits to purchase receivables and expires in September 2028. As of September 30, 2026, the affiliated utility subsidiaries were in compliance with all requirements under the agreement.

Debt Covenants and Borrowing Limitations

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of September 30, 2026, this contractually defined percentage was 56.0%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under these credit agreements. This condition also applies, at the more restrictive level of $50 million of debt outstanding, in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

ATM Program

In November 2025, AEP filed a prospectus supplement under which it may sell up to $3.5 billion of its common stock through an ATM program. In the first quarter of 2026, two million shares of common stock were issued for $264 million in net proceeds. In addition to these issuances and sales of shares of common stock, AEP also may use the ATM program to enter into forward sale agreements. As of September 30, 2026, AEP had issued six million shares in forward sale agreements through its ATM program with expected proceeds of $684 million.

See “Forward Equity Agreements” section of Note 12 for additional information regarding shares issued or expected to be issued under forward sale agreements.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.97 per share in October 2026. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 12 for additional information.

Credit Ratings

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings. In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

CASH FLOW

AEP relies primarily on cash flows from operations, debt issuances, issuances of common stock and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper and bank term loans, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

Operating Activities

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Deferred Income Taxes, Asset Impairments and Other Related Charges and AFUDC.

Net Cash Flows from Operating Activities increased by $636 million primarily due to the following:

•A $539 million increase in cash from Change in Other Noncurrent Liabilities. This increase is primarily due to the increase in customer deposits, the timing of deferred revenue on customer infrastructure projects and changes in regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

•A $422 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $95 million increase in cash due to a discretionary contribution to the qualified pension plan made in 2025. See Note 7 - Benefit Plans for additional information.

•A $47 million increase in cash due to changes in risk management contract collateral positions.

These increases in cash were partially offset by:

•A $370 million decrease in cash from the Change in Certain Components of Working Capital. This decrease is primarily due to timing of accounts receivable collections and an increase in fuel, materials and supplies driven by higher coal inventory on hand, partially offset by the increase in customer deposits.

Investing Activities

Net Cash Flows Used for Investing Activities increased by $3.4 billion primarily due to the following:

•A $3.1 billion increase in Construction Expenditures primarily due to increases in Vertically Integrated Utilities of $1.1 billion, Transmission and Distribution Utilities of $1 billion and AEP Transmission Holdco of $600 million.

•A $737 million increase primarily due to the acquisitions of five generation facilities in 2026. See “Acquisitions” section of Note 6 for additional information.

•A $424 million decrease due to higher contributions in aid of construction primarily due to increases in Transmission and Distribution Utilities of $237 million and AEP Transmission Holdco of $185 million.

Financing Activities

Net Cash Flows from Financing Activities increased by $2.2 billion primarily due to the following:

•A $1.7 billion increase due to changes in short-term debt.

•A $1.2 billion increase in security deposits primarily due to the collection of additional deposits under ERCOT’s Batch Zero process.

•A $970 million decrease in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

•A $777 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $230 million increase in issuances of common stock primarily under AEP’s ATM Program. See Note 12 - Financing Activities for additional information.

These increases in cash were partially offset by:

•A $2.8 billion decrease due to proceeds from the 2025 Midwest Transmission Holdings Noncontrolling Interest transaction. See “Noncontrolling Interest in Midwest Transmission Holdings” section of Note 6 for additional information.

See the “Financing Activities Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 2026 through October 28, 2026, the date that the third quarter Form 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately$15.6 billion of capital expenditures in 2026. For the five-year period, 2027 through 2031, management forecasts capital expenditures of $100.4 billion. Management’s forecasted capital expenditures reflect planned investments for transmission infrastructure and new generation resources to support existing customers and forecasted large load increases and continued improvements in distribution system reliability.

Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, technology advancements, inflation and the ability to access capital. Management has funded, or expects to fund, these capital expenditures through cash flows from operations and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.

The 2027-2031 estimated capital expenditures by Business Segment are as follows:

SIGNIFICANT CASH REQUIREMENTS

A summary of significant cash requirements is included in the 2025 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2025 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and asset retirement obligations.

ACCOUNTING STANDARDS

See Note 2 - New Accounting Standards for information related to accounting standards and SEC rulemaking activity.