AEP Transmission Company, LLC

EXECUTIVE OVERVIEW

AEP CONSOLIDATED RESULTS OF OPERATIONS

Earnings Attributable to AEP Common Shareholders decreased from $1.2 billion in 2025 to $713 million 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.

•A decrease in sales volumes in the residential class driven by favorable weather in 2025.

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

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

•Favorable mark-to-market economic hedging activity.

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

Earnings Attributable to AEP Common Shareholders decreased from $2 billion in 2025 to $1.6 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.

•Unfavorable mark-to-market economic hedging activity.

•A decrease in sales volumes in the residential class driven by favorable weather in 2025.

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

•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 driven primarily by new data processing load added in the commercial and industrial customer classes.

•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 the estimated impact of the probable, partial disallowance of costs included in AEP Texas’ UTM filing.

(d)Represents probable liability related to SWEPCo’s agreements with certain existing wholesale customers and current discussions with one remaining existing wholesale customer under generation supply contracts, which is expected to result in credits to these wholesale customers.

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

(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 probable liability related to SWEPCo’s agreements with certain existing wholesale customers and current discussions with one remaining existing wholesale customer under generation supply contracts, which is expected to result in credits to these wholesale customers.

(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

The electric utility industry is undergoing a historic transformation, fueled by rapid and projected load growth, especially from data processing and other energy-intensive operations, as well as shifting regulator and customer expectations, evolving public policies, rising stakeholder demands, demographic changes, new competitive pressures, emerging technologies, necessary reliability investments and volatile commodity markets. AEP projects growth in system peak demand across its diversified service territory, with especially strong projected growth in Indiana, Ohio, Oklahoma and Texas. To meet this accelerating demand, AEP outlined a $78 billion, five-year capital plan focused on strengthening transmission infrastructure, adding new generation resources to serve both existing customers and forecasted large load additions and continuing to enhance distribution system reliability. Throughout this investment cycle, AEP remains committed to focusing on customer affordability. AEP expects to utilize various levers to address affordability including incremental load growth, rate design, continued operation and maintenance expense efficiency and financing mechanisms, such as securitizations.

AEP has advanced large load tariff proposals and tariff modifications aimed at enabling the rapid interconnection of committed large load customers while protecting existing customers from increased costs. The new tariffs are designed to protect existing customers by strengthening and lengthening contract terms with large customers. These new protections include contract lengths of up to 20 years and take-or-pay contractual minimums which can require a customer to pay for as much as 80-90% of their contracted demand. In practice, these provisions reduce risks around the buildout of large load infrastructure on existing customers, with a goal of promoting stability and affordability. As of March 31, 2026, these tariff proposals were filed in eight of AEP’s jurisdictions, with four receiving approval from state commissions. During the second quarter of 2026, the Virginia State Commission approved APCo’s large load tariff proposal, which applies to new large load additions greater than or equal to 150 MW on an aggregated basis or 100 MW on an individual basis. As of June 30, 2026, there were three pending proposals in Michigan, Oklahoma and SWEPCo-Texas. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to connect large load customers to the grid while also advancing system reliability, resiliency and affordability across its service territory.

AEP continues to secure resources to support forecasted load requirements in its regulated jurisdictions including:

•The addition of 1,013 MWs of owned generating capacity in 2026.

•Signing agreements in 2026 to acquire 1,838 MWs in additional generation facilities.

•Requests for proposals seeking approximately 12,100 MWs of generating capacity.

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

•Long-term transmission construction partnership with a major U.S.-based infrastructure services company.

PJM Proposed Reforms

In July 2026, the PJM Board approved near-term resource adequacy reforms intended to address projected reliability concerns associated with significant forecasted load growth and capacity shortages. The package directs PJM to seek FERC approval of a Reliability Backstop Procurement mechanism and an Interim Resource Adequacy Service for new large load customers that do not provide sufficient capacity resources to meet their resource adequacy needs. The reforms also include the creation of a Large Load Registry and new requirements for electric distribution utilities to provide information regarding certain large load interconnection requests. PJM expects to conduct a centralized procurement process beginning in September 2026.

Fixed Resource Requirement entities are excluded from the Reliability Backstop Procurement targets and associated cost allocation. AEP's Fixed Resource Requirement operating companies within PJM also may be affected in their role as electric distribution utilities. Under the proposed framework, beginning June 1, 2027, electric distribution utilities would be required to administer an Interim Resource Adequacy Service for certain new large load customers that do not provide sufficient capacity resources to meet applicable reliability requirements. The proposal also requires electric distribution utilities to administer a FERC-approved compensation mechanism for qualifying large load customers that are directed to reduce their electricity consumption.

The PJM proposal also includes provisions intended to mitigate impacts associated with a transmission owner's withdrawal from PJM. Under the proposal, a withdrawing transmission owner that participates in the Reliability Backstop Procurement program could be required to satisfy certain future obligations associated with resources procured through that program or charges allocated to load on an accelerated basis prior to withdrawal, or otherwise provide for continued payment of such obligations through the applicable commitment term. These provisions are intended to prevent costs associated with committed reliability resources from being shifted to remaining PJM participants.

PJM has not yet filed the proposal with the FERC, and the ultimate form of any approved tariff revisions, implementation requirements, cost recovery mechanisms and operational impacts remains uncertain. At this time, AEP cannot predict the outcome of the FERC proceeding or estimate the potential impact, if any, that any final approved provisions may have on its financial condition, results of operations or cash flows. AEP will continue to monitor the proceeding.

Customer Demand

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. Through the first half of 2026, AEP experienced higher customer demand, driven primarily by new data processing load added in the commercial and industrial customer classes. This growth was partially offset by weather-related impacts in the residential class, including favorable weather in the first and second quarters of 2025 and normal weather through the first half of 2026. The table below shows the percentage change in sales volume by customer class.

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

(b)Percentage change for the six months ended June 30, 2026 as compared to the six months ended June 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

In March 2026, I&M acquired the Oregon Clean Energy Center (Oregon Plant). In May 2026, APCo acquired the Grover Hill Wind Project (Grover Hill Wind). These transactions reflect the Companies’ 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 Natural Gas Generation

In December 2024, SWEPCo filed an application for a CCN with the APSC, LPSC and PUCT for construction of the Hallsville Natural Gas Plant (450 MWs) and the fuel conversion of Welsh Plant, Units 1 and 3 to natural gas. In the application for the CCN, SWEPCo seeks to site the Hallsville Natural Gas Plant at the location of the now-retired Pirkey Plant. In February 2026, the APSC approved both projects and regulatory proceedings in Louisiana and Texas are still underway. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation and term sheet with the LPSC agreeing the application for a CCN should be approved. SWEPCo estimates the combined capital cost of these projects to be approximately $723 million and the projects would be placed in service between December 2027 and May 2028.

In September 2025, PSO filed an application with the OCC seeking regulatory approval of a new 450 MW combustion turbine configuration at its existing Northeastern facility in Oklahoma as part of a project portfolio, which was approved in May 2026. The combustion turbines are projected to be online by the end of 2028.

In February 2026, I&M entered into a PSA to acquire the Big Sandy Peaker Plant, a six-unit, 318 MW combustion turbine plant located in Kenova, West Virginia. In April 2026, I&M filed an application with the IURC seeking approval of the purchase under its EGR plan. The acquisition is expected to close in the second half of 2026.

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 the approval of the estimated project costs and associated ratemaking and accounting treatment. A final order from the IURC is expected in December 2026.

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

Significant Approved Renewable Generation and Storage Filings

AEP received approval from various state regulatory commissions to acquire approximately 884 MWs of owned renewable 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 approval from various state regulatory commissions for 924 MWs of renewable PPAs. The following table summarizes regulatory approvals received for active renewable projects that are not yet in service as of June 30, 2026:

(a)PSO has one wind project and one solar project under construction.

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:

(a)Five wind resources totaling 574 MWs from the 2024 RFP were contracted and approved by the IURC. The 918 MW Sycamore Plant was also selected through the 2024 RFP and was filed with the IURC for approval in April 2026. I&M expects to file several additional projects selected through the 2024 RFP in the second half of 2026.

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 June 30, 2026, by year, for the five-year period 2026-2030:

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.

AEP Texas has executed Letters of Agreement for approximately 45 gigawatts of incremental load by 2030, including approximately 40 gigawatts of prospective load seeking consideration under ERCOT’s Batch Zero process, a one-time transitional interconnection process established by ERCOT and approved by the PUCT in 2026. The ERCOT Batch Zero process 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 40 gigawatts of prospective load seeking consideration for participation in the Batch Zero process.

ERCOT is expected to identify projects eligible for participation in Batch Zero, while the PUCT is expected to issue additional SB 6 rulemaking guidance in August 2026. ERCOT expects to provide load ramp information to eligible Batch Zero projects in April 2027, enabling large load customers to determine whether to proceed with an interconnection agreement and reserve its electric capacity. These activities are expected to provide greater clarity regarding large load interconnection requirements, transmission infrastructure needs and the timing and scale of future load growth. However, the amount, timing and cost responsibility associated with these prospective large load interconnections remain subject to ongoing ERCOT and PUCT actions.

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

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 are expected in the third quarter of 2026. In conjunction with the Commissioner Memorandum, AEP Texas recognized an unfavorable pretax impact of $23 million in May 2026 primarily attributable to a portion of the deferrals included in the UTM application period.

As of June 30, 2026, AEP Texas had deferred approximately $72 million of eligible costs as a regulatory asset of which $65 million will be included in AEP Texas’ next UTM application. 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 are not approved for recovery, it could reduce future net income and cash flows and impact financial condition.

2026 West Virginia Orders

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. See “2025 West Virginia Securitization Filing” section of Note 4 for additional information.

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.

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. This order also allows the Companies to recognize carrying charges on revised MRBC under-recovery balances starting September 2024 and to recover the updated MRBC under-recovery with carrying charges through current ENEC surcharge rates over a period to be determined in the Companies’ 2026 ENEC proceeding. The April 2026 order also noted that collection of the revenue requirement related to inclusion of a stand-alone NOLC deferred tax asset in MRBC rates may be subject to refund, pending the future issuance of a PLR or other guidance by the IRS.

In May 2026, a group of APCo customers submitted an appeal to the West Virginia Intermediate Court of Appeals alleging that the WVPSC erred in its April 2026 order approving: (a) the Inflation-Based Rate Adjustment without adequate findings, evidentiary support or reasoned explanation demonstrating the approval of reasonable rates under WVPSC statutes, (b) a final MRBC true-up without sufficient record support and (c) recovery mechanisms associated with the ENEC, vegetation management, Broadband and securitization-related ratemaking. This appeal was dismissed by the West Virginia Intermediate Court of Appeals for lack of jurisdiction. The group of APCo customers subsequently submitted the appeal to the West Virginia Supreme Court. In July 2026, an intervening party submitted an appeal to the West Virginia Supreme Court 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 “2026 ENEC Update Filing”, “West Virginia Modified Rate Base Cost (MRBC) Surcharge Update Filing” and “2025 West Virginia Securitization Filing” sections 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.

2025 Virginia Securitization Filing

In May 2026, APCo issued 20-year securitization bonds to finance approximately $1.4 billion of jurisdictional costs, including; (a) $1.2 billion of certain Virginia jurisdictional Property, Plant and Equipment balances for the Amos and Mountaineer Plants, (b) $141 million of Virginia jurisdictional major storm operation and maintenance expenses deferred as Regulatory Assets during the 2024-2025 biennial period and (c) $11 million of up-front financing costs. After issuing the securitization bonds, APCo implemented a rider to recover annual securitization debt financing costs and the Base Rate Reduction (BRR) Rider to credit customers for the recovery of, and return on, the Amos and Mountaineer Plant costs currently included in APCo Virginia base rates.

Indiana Earnings Test

In February 2026, I&M submitted its FAC filing and earnings test evaluation for the period ended November 2025. I&M proposed an over-earnings credit to customers for the earnings test period ending November 2025 of $53 million based on requested modifications to jurisdictional cost allocations to more accurately reflect I&M’s cost to serve Indiana retail customers. In June 2026, the IURC issued an order approving the jurisdictional cost allocation modifications and the $53 million over-earnings customer credit. See “Indiana Earnings Test” section of Note 4 for additional information.

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 May 2026, intervenors recommended certain modifications to KPCo’s cost recovery proposal or that KPCo’s Mitchell CPCN request be denied. A hearing was held at the KPSC in July 2026 and a KPSC decision is expected in the fourth quarter of 2026.

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

In July 2026, WVPSC staff submitted testimony recommending that WPCo’s Mitchell CPCN be approved with certain modifications to WPCo’s proposed cost recovery, while intervenors submitted testimony that did not offer an opinion as to whether WPCo’s Mitchell CPCN should be approved and recommended adjustments to WPCo’s cost recovery if WPCo’s Mitchell CPCN is approved. A hearing at the WVPSC is scheduled for September 2026 and an order from the WVPSC is expected in the fourth quarter of 2026.

As of June 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 $643 million ($383 million at WPCo and $260 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.

Indiana House Enrolled Act 1002

On February 26, 2026, House Enrolled Act 1002 (HEA 1002) was signed into law in Indiana. Among other things, 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.

In July 2026, the IURC launched investigations into the risks and changes in those risks to the electricity suppliers and customers in Indiana as a result of the electricity supplier implementing an MYRP. The IURC also launched an investigation into the continued use of trackers or riders by electricity suppliers during MYRPs. Technical conferences to discuss these investigations are scheduled for August 2026.

In July 2026, I&M submitted a notice of intent to file an Indiana MYRP with the IURC no later than September 1, 2026. If I&M is not able to recover its costs to serve Indiana retail customers, including a fair return on investments, it could 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. The offtake arrangement remains subject to specified conditions, however, in June 2026, the deadline for those conditions was extended by mutual agreement of the parties. Should the revised conditions not be satisfied in December 2026, AEP will be entitled to additional consideration to account for the extended timeline.

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 Holdings, 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 cap 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 June 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 June 30, 2026, AEP had NOLC regulatory assets of $97 million, of which $85 million are classified as pending final regulatory approval and $12 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 June 30, 2026, AEP owned generating capacity of approximately 26,500 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. The Federal EPA administration has proposed to revise or repeal portions of those new rules. 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 PM 2.5 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 PM 2.5 standard. In June 2026, the United States Court of Appeals for the District of Columbia Circuit denied the request.

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 U.S. 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. 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 PM 2.5 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 February 2026, the Federal EPA repealed the 2009 findings of contribution and endangerment for light-duty, medium-duty and heavy-duty vehicles and engines, which determined that GHG emissions from motor vehicles endanger public health and welfare. The Federal EPA also repealed the GHG standards for these vehicle and engine categories as part of that rulemaking. The 2009 Endangerment Finding is the basis of the Federal EPA’s authority to regulate GHG emissions under the Clean Air Act. Management is evaluating the Federal EPA’s proposed repeal of the 2009 motor vehicle Endangerment Finding and its impact on the Federal EPA’s authority to regulate GHG emissions from electric generators. Management cannot predict the outcome of the current litigation or the Federal EPA’s proposed action related to the GHG rule or its recent repeal of the Endangerment Finding related to emissions from fossil-fuel fired sources or any litigation that may result. More stringent rules directed at the fossil-fuel fired electric utility industry could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life, if those rules remain in place. 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. The proposal is expected to be finalized by the end of 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. Management is evaluating the compliance alternatives in the 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. 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 June 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. 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. In July 2026, SWEPCo, PUCT staff and certain intervenors filed an unopposed stipulation and settlement agreement with the PUCT agreeing the application for a CCN should be approved. Additionally, in July 2026, SWEPCo and the LPSC staff filed a joint stipulation and term sheet with the LPSC agreeing the application for a CCN should be approved.

(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 six months ended June 30, 2026 as compared to the three months ended and six months ended June 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 six months ended June 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 $168 million primarily due to the following:

•A $179 million increase in base rates and rider revenues.

•A $60 million increase in weather-normalized revenues primarily in the commercial and industrial classes.

•A $48 million decrease in fuel revenues primarily due to decreases at APCo and SWEPCo, partially offset by an increase at I&M.

•A $23 million decrease at SWEPCo due to a probable credit to certain existing wholesale generation customers.

•Off-system Sales decreased $35 million primarily due to Rockport Plant, Unit 2 merchant sales and economic hedging activity at I&M.

•Transmission Revenues decreased $27 million primarily due to the following:

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

• A $32 million increase due to continued transmission investment.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to decreases at APCo and SWEPCo, partially offset by increases at I&M and PSO.

•Other Operation and Maintenance expenses increased $74 million primarily due to the following:

•A $41 million increase in generation expenses due to non-outage maintenance, nuclear and renewable energy.

•A $24 million increase in distribution-related expenses driven by system improvements, forestry, storms, customer driven third-party work and amortization of storm-related regulatory assets.

•A $10 million increase in employee-related costs.

•Depreciation and Amortization expenses increased $37 million primarily due to the following:

•A $31 million increase due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $10 million increase at KPCo primarily due to the amortization of securitized assets and PPA rider activity.

•A $7 million decrease at APCo primarily due to a decrease in depreciation expense at Amos and Mountaineer plants due to the issuance of Virginia securitization bonds.

•Taxes Other Than Income Taxes increased $21 million primarily due to the following:

•A $10 million increase at SWEPCo and I&M primarily due to an increase in property taxes.

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

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

•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $62 million primarily due to higher long-term debt balances.

•Income Tax Benefit decreased $73 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 $7 million decrease due to a decrease in flow-through cost of removal.

•A $39 million increase due to an increase in PTCs.

•A $15 million increase due to a decrease in pretax book income.

•Retail Revenues increased $351 million primarily due to the following:

•A $371 million increase in base case and rider revenues.

•A $112 million increase in weather-normalized revenues primarily in the commercial and industrial classes, partially offset by a decrease in the residential class.

•A $15 million increase due to a decrease in regulatory provisions for refund at I&M.

•A $104 million decrease in fuel revenues primarily due to decreases at APCo and SWEPCo, partially offset by an increase at I&M.

•A $27 million decrease in weather-related usage primarily in the residential class driven by a 15% decrease in heating degree days primarily in the western region.

•A $23 million decrease at SWEPCo due to a probable credit to certain existing wholesale generation customers.

•Off-system Sales increased $47 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.

•Transmission Revenues increased $12 million primarily due to the following:

• A $60 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.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses decreased $21 million primarily due to decreases at APCo and SWEPCo, partially offset by increases at I&M and PSO.

•Other Operation and Maintenance expenses increased $207 million primarily due to the following:

•A $74 million increase in generation expenses due to outage and non-outage maintenance, nuclear and renewable energy.

•A $34 million increase in vegetation management costs.

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

•A $25 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 $21 million increase in storm expenses.

•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 $81 million primarily due to the following:

•A $52 million increase primarily due to a higher depreciable base at I&M, PSO and SWEPCo.

•A $10 million increase at KPCo primarily due to the amortization of securitized assets.

•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.

•A $7 million increase at SWEPCo primarily due to higher over-recovery of costs and allowable return associated with the generation rider.

•A $6 million decrease at I&M due to Michigan PTC deferral activity.

•Taxes Other Than Income Taxes increased $31 million primarily due to the following:

•A $19 million increase in property taxes at APCo, PSO and SWEPCo.

•An $8 million increase due to higher business and occupation taxes at APCo.

•Allowance for Equity Funds Used During Construction increased $12 million primarily due to a higher AFUDC base and an increase in equity return rates primarily at I&M, SWEPCo and KPCo.

•Non-Service Cost Components of Net Periodic Benefit Cost increased $12 million primarily due to the continued recognition of unfavorable 2022 pension plan asset returns used to calculate the 2026 pension expense.

•Interest Expense increased $107 million primarily due to the following:

•An $82 million increase primarily due to higher long-term debt balances.

•A $10 million increase at PSO and SWEPCo due to a prior year deferral of expenses as a result of the IRS PLR received regarding the treatment of stand-alone NOLCs in retail ratemaking.

•A $5 million increase at SWEPCo related to the Texas tax normalization rider amortization.

•Income Tax Benefit increased $20 million primarily due to the following:

•A $112 million increase due to an increase in PTCs.

•A $24 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 $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.

TRANSMISSION AND DISTRIBUTION UTILITIES

Summary of KWh Energy Sales for Transmission and Distribution Utilities

(a)Represents energy delivered to distribution customers.

(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 $102 million primarily due to the following:

•A $94 million increase in rider revenues in Ohio and Texas.

•An $11 million increase in weather-normalized revenues primarily in the commercial class in Texas.

•A $7 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days in Texas.

•Off-system Sales decreased $7 million primarily due to decreased sales of OVEC purchased power driven by lower market prices.

•Transmission Revenues increased $33 million primarily due to continued transmission investments in Ohio and Texas.

•Other Revenues increased $6 million primarily due to the taxable portion of payments received from customers for large interconnection projects in Texas.

•Purchased Electricity for Resale expenses decreased $17 million primarily due to the following:

•A $23 million decrease in OVEC purchased power costs in Ohio.

•A $7 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $114 million primarily due to the following:

•A $75 million increase primarily due to recoverable PJM transmission expenses in Ohio.

•An $18 million increase due to the probable, partial disallowance of regulatory assets associated with the UTM deferrals in Texas.

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

•A $6 million increase primarily due to recoverable distribution vegetation management expenses in Ohio.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base in Texas.

•Taxes Other Than Income Taxes increased$31 million primarily due to the following:

•A $23 million increase in property taxes in Ohio.

•A $5 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $9 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $18 million primarily due to higher long-term debt balances in Texas.

•Income Tax Expense decreased $14 million primarily due to Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•Retail Revenues increased $135 million primarily due to the following:

•An $82 million increase in rider revenues in Ohio and Texas.

•A $60 million increase due to higher prices for purchased power to serve OPCo’s SSO customers.

•A $24 million increase in weather-normalized revenues primarily in the residential class in Ohio and commercial class in Texas.

•A $40 million decrease in weather-related usage primarily driven by a 6% decrease in cooling degree days in Ohio and a 3% decrease in cooling degree days in Texas.

•Off-system Sales increased $18 million primarily due to increased sales of OVEC purchased power driven by higher market prices and volume in Ohio.

•Transmission Revenues increased $53 million primarily due to continued transmission investment in Ohio and Texas.

•Other Revenues increased $10 million primarily due to the following:

•A $15 million increase primarily due to the taxable portion of payments received from customers for large interconnection projects in Texas.

•A $6 million decrease primarily due to lower third-party Legacy Generation Resource Rider revenues related to the recovery of OVEC costs in Ohio.

•Purchased Electricity for Resale expenses decreased $13 million primarily due to the following:

•A $44 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.

•A $30 million decrease in OVEC purchased power costs in Ohio.

•A $58 million increase in recoverable auction purchases to serve SSO customers in Ohio.

•Purchased Electricity from AEP Affiliates expenses increased $5 million primarily due to an increase in recoverable purchases to serve SSO customers in Ohio.

•Other Operation and Maintenance expenses increased $117 million primarily due to the following:

•A $50 million increase in recoverable PJM transmission expenses in Ohio.

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

•A $15 million increase related to recoverable energy assistance program expenses for qualified Ohio customers.

•A $14 million increase primarily due to recoverable distribution vegetation management expenses in Ohio.

•An $11 million increase in recoverable transmission storm restoration costs and vegetation management expenses in Ohio.

•Depreciation and Amortization expenses increased $23 million due to the following:

•An $18 million increase due to a higher depreciable base in Texas.

•A $13 million increase primarily due to the deferral of income tax benefit from Excess ADIT credits to be refunded to customers as approved in the 2025 Ohio base rate case.

•A $7 million decrease primarily due to the amortization of regulatory liabilities related to Transition Funding customer refunds in Texas.

•Taxes Other Than Income Taxes increased $26 million due to the following:

•An $18 million increase in property taxes in Ohio.

•A $7 million increase in state excise taxes due to increased billed KWhs in Ohio.

•Allowance for Equity Funds Used During Construction increased $15 million primarily due to a higher AFUDC base in Texas.

•Interest Expense increased $11 million primarily due to the following:

•A $24 million increase due to higher long-term debt balances in Texas.

•An $8 million decrease due to an increase in the debt component of AFUDC in Texas.

•A $6 million decrease due to the deferral of eligible costs related to the UTM in Texas.

•Income Tax Expense decreased $8 million primarily due to the following:

•An $18 million decrease primarily due to Excess ADIT credits refunded to customers as approved in the 2025 Ohio base rate case.

•A $13 million increase due to an increase in pretax book income.

AEP TRANSMISSION HOLDCO

Summary of Investment in Transmission Assets for AEP Transmission Holdco

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

•Transmission Revenues decreased $147 million primarily due to the following:

•A $67 million increase due to continued transmission investment.

•Other Operation and Maintenance expenses increased $11 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $9 million primarily due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $9 million due to higher property taxes driven by higher transmission investment.

•Interest Expense increased $9 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $202 million primarily due to the following:

•A $254 million increase 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 $38 million decrease due to a decrease in pretax book income.

•Net Income Attributable to Noncontrolling Interests decreased $29 million primarily due to the following:

•A $25 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

•Transmission Revenues decreased $91 million primarily due to the following:

•A $123 million increase due to continued transmission investment.

•Other Operation and Maintenance expenses increased $27 million primarily due to an increase in employee-related costs, vegetation management expenses, affiliated rent expense and other miscellaneous expenses.

•Depreciation and Amortization expenses increased $24 million due to a higher depreciable base.

•Taxes Other Than Income Taxes increased $24 million primarily due to higher property taxes driven by increased investment.

•Interest Expense increased $21 million primarily due to higher long-term debt balances and interest rates.

•Income Tax Expense increased $202 million primarily due to the following:

•A $38 million decrease due to a decrease in pretax book income.

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

•A $52 million increase primarily due to the Midwest Transmission Holdings noncontrolling interest transaction that closed in June 2025.

GENERATION & MARKETING

•Retail, Trading and Marketing increased $94 million primarily due to higher market prices in 2026 and MTM hedging gains.

•Merchant Generation increased $35 million primarily due to higher realized prices in 2026.

•Other Revenues increased $14 million primarily due to continued progress on projects in 2026.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $95 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses increased $6 million primarily due to lower renewable contract restructuring and termination proceeds in 2026.

•Income Tax Expense increased $11 million primarily due to an increase in pretax book income.

•Retail, Trading and Marketing increased $268 million primarily due to higher market prices in 2026, partially offset by reduced MTM hedging gains.

•Merchant Generation increased $44 million primarily due to higher realized prices in 2026.

•Other Revenues increased $36 million primarily due to continued progress on projects in 2026.

•Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expenses increased $366 million primarily due to an increase in energy costs in 2026.

•Other Operation and Maintenance expenses decreased $15 million primarily due to renewable contract restructuring and termination proceeds in 2026.

•Interest and Investment Income increased $9 million primarily due to an increase in interest income due to higher advances to affiliates.

CORPORATE AND OTHER

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $71 million in 2025 to a loss of $115 million in 2026 primarily due to:

•A $31 million decrease in Income Tax Benefit primarily due to the following:

•A $25 million decrease due to an increase in state taxes.

•A $5 million decrease due to a decrease in PTCs.

•A $19 million increase in interest expense primarily due to higher long-term debt balances.

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $97 million in 2025 to a loss of $224 million in 2026 primarily due to:

•A $51 million decrease in Income Tax Benefit primarily due to the following:

•A $37 million decrease due to a decrease in PTCs.

•A $26 million decrease due to an increase in state taxes.

•A $16 million increase due to a decrease in pretax book income.

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

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

AEP CONSOLIDATED INCOME TAXES

Income Tax Expense increased $303 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 $21 million increase due to an increase in state taxes.

•A $50 million decrease due to a decrease in pretax book income.

•A $34 million decrease due to an increase in PTCs.

Income Tax Expense increased $222 million primarily due to the following:

•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 $20 million increase due to an increase in state taxes.

•A $75 million decrease due to an increase in PTCs.

•A $46 million decrease due to a decrease in pretax book income.

•A $24 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.

•A $14 million decrease due to an increase in amortization of Excess ADIT.

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 61.4% as of December 31, 2025 and June 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 June 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 June 30, 2026, available liquidity was approximately $7.3 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 six months of 2026 was $2.1 billion. The weighted-average interest rate for AEP’s commercial paper for the six months ended June 30, 2026 was 3.93%.

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 June 30, 2026 was $535 million with maturities ranging from July 2026 to June 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 2027. As of June 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 June 30, 2026, this contractually defined percentage was 52.4%. 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, 2 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.

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 $0.95 per share in July 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 $750 million primarily due to the following:

•A $540 million increase in cash from Change in Other Noncurrent Liabilities. This increase is primarily due to an increase in security deposits held for customers and changes in regulatory liabilities driven by timing differences in refunds to customers under rate rider mechanisms.

•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 $75 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.

•A $24 million increase in cash due to changes in risk management contract collateral positions.

Investing Activities

Net Cash Flows Used for Investing Activities increased by $1.3 billion primarily due to the following:

•A $1.6 billion increase in Construction Expenditures primarily due to increases in Transmission and Distribution Utilities of $698 million and Vertically Integrated Utilities of $506 million.

•A $319 million decrease due to higher contributions in aid of construction primarily due to increases in Transmission and Distribution Utilities of $208 million and AEP Transmission Holdco of $115 million.

Financing Activities

Net Cash Flows from Financing Activities increased by $651 million primarily due to the following:

•A $1.9 billion increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.

•A $1.5 billion increase due to changes in short-term debt.

•A $273 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.

•A $254 million increase in retirements of long-term debt. See Note 12 - Financing Activities 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 June 30, 2026 through July 30, 2026, the date that the second quarter Form 10-Q was filed.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately$12.8 billion of capital expenditures in 2026. For the four-year period, 2027 through 2030, management forecasts capital expenditures of $65.1 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 2026-2030 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.