AEP 10-K & 10-Q changes, risk factors and insider trading

AEP’s business planand callscapital investment plans call for extensive investment in capital improvements and additions, including the construction or acquisition of additional transmission and generation facilities, installation and interconnection with data centers, modernizing existing infrastructure, installation of environmental upgrades and retrofits as well as other initiatives. AEP’s public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. If these regulatory commissions do not approve adjustments to the rates charged, affected AEP subsidiaries would not be able to recover the costs associated with their investments. This would cause financial results to be diminished.

AEP’sThe transmissionbusiness and capital investment strategyplans andof AEP are subject to execution are dependent on federal and state regulatory policy.risks. (Applies to all Registrants)

A significant portion of AEP’s earnings is derived from transmission investments and activities. FERC policy currently favorssupports the expansion and updating of the transmission infrastructure within its jurisdiction. If the FERC were to adopt a different policy, if states were to limit or restrict such policies, or if transmission needs do not continue or develop as projected, AEP’s strategy of investing in transmission could be impacted. Management believesFurther, AEP’s experience with transmission facilitiesstrategy constructionseeks andto operation gives AEP an advantage over other competitors in securingobtain authorization or to win bids to install, construct and operate new transmission lines and facilities. However, there can be no assurance that PJM, SPP, ERCOT or other RTOs will authorize new transmission projects or will award such projects to AEP.

Certain elements of AEP’s transmission formula rates have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on AEP’s business, financial condition, results of operations and cash flows.collected. (Applies to all Registrants other than AEP Texas)

AEP provides transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by AEP to calculate its respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of AEP’s rates accepted or approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of its respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative. In addition, interested parties may challenge the annual implementation and calculation by AEP of its projected rates and formula rate true-up pursuant to its approved formula rate templates under AEP’s formula rate implementation protocols. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC can make appropriate prospective adjustments to them and/or disallow any of AEP’s inclusion of those aspects in the rate setting formula.

AEP owns, develops, constructs, manages and operates electric generation, transmission and distribution facilities. A key component of AEP's growth is its ability to construct and operate these facilities. As part of these operations AEP must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. Should AEP be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, it could reduce future net income and cash flows and impact financial condition. Any failure to timely construct contracted generation, transmission and distribution facilities or to negotiate successful project development agreements for new facilities with third-partiesthird-parties, including new data centers and large load customers, could haveimpact similarfuture results.net income and cash flows and impact financial condition. Any failure to timely construct contracted generation, transmission and distribution facilities or to negotiate successful project development agreements for new facilities with third-parties, including new data centers and other large load customers, could impact future net income and cash flows and impact financial condition.

AEP primarily generates electricity at large central facilities and delivers that electricity to customers over its transmission and distribution facilities to customers usually situated within an exclusive franchise. This method results in economies of scale and generally lower costs than newer technologiestechnologies, such as fuel cells and microturbines, and distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines, small modular reactorsturbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery. These developments can challenge AEP’s competitive ability to maintain relatively low cost, efficient and reliable operations, to establish fair regulatory mechanisms and to provide cost-effective programs and services to customers. Further, inIn the event that alternativelower generationcost resourcesalternatives arefor mandated,generation, subsidizedas a result of changing regulatory policies, subsidies or encouragedadvances throughin legislation or regulation or otherwisetechnology, are economically competitive and added to the available generation supply, such resourcesthey could displace acurrent higherresources marginal cost generating units, which couldor reduce the price at which market participants sell their electricity.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants. In addition, although management has no reason to anticipate a serious nuclear incident at the Cook Plant, if an incident did occur, it could harm results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Moreover, a major incident at any nuclear facility in the U.S. could require AEP or I&M to make material contributory payments.

Results are likely to be affected by differencesDifferences in the market and transmission structures in various regional power markets.markets are likely to affect results. The rules governing the various RTOs, including SPP and PJM, may also change from time to time which could affect costs or revenues. Existing, new or changed rules of these RTOs could result in significant additional fees and increased costs to participate in those structures, including the cost of transmission and generation facilities built by others due to changes in rules and allocations, including transmission rate design. In addition, these RTOs may assess costs resulting from improved transmission reliability, reduced transmission congestion and firm transmission rights. As members of these RTOs, AEP’s subsidiaries are subject to certain additional risks, including the allocation among existing members, of losses caused by unreimbursed defaults of other participants in these markets and resolution of complaint cases that may seek refunds of revenues previously earned by members of these markets.

Owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with new reliability standards may subject AEP to higher operating costs and/or increased capital expenditures. While management expects to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner. If AEP were found not to be in compliance with the mandatory reliability standards, AEP could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2024,2025, AEP Texas did business with approximately 135146 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2024,2025, AEP Texas’ two largest REPs accounted for 40%38% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

•Information technology failure, including failure of artificial intelligenceAI technology, that impairs AEP’s information technology infrastructure or disrupts normal business operations.

•Catastrophic events such as extreme weather, fires, earthquakes, explosions, hurricanes, tornadoes, icewinter storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

AEP’s operations are dependent upon the proper functioning of its internal systems, including the information technology systems that support our underlying business processes. Any significant failure or malfunction of such information technology systems may result in disruptions of our operations. In the ordinary course of business, we rely on information technology systems, including the internet and third-party hosted services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of our customers, employees, retirees and shareholders and (iv) data with respect to invoicing and the collection of payments, accounting, procurement and supply chain activities. OurAEP’s information technology systems are dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. These providers’ systems are susceptible to cybersecurity and data breaches, outages from fire, floods, power loss, telecommunications failures, break-ins and similar events. Failure to prevent or mitigate data loss from system failures or outages could materially affect AEP’s results of operations, financial position and cash flows.

AEP is subject to income taxation at the federal level and by certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the applicable tax laws and related regulations, administrative interpretations and judicial determinations, including tax incentives and credits designed to support the sale of energy from utility scale renewable energy facilities. While management believes AEP complies with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxes on the company. At the Federalfederal level, management is monitoring the potential for changes in current tax policy, including tax rates, tax credits and incentives. Any adverse developments in tax laws, incentives, credits or regulations, including legislative changes, judicial holdings or administrative interpretations, could have a material and adverse effect on financial condition and results of operations.

If AEP is unable to access capital markets or insurance markets on reasonable terms, for any reason, including negative publicity, it could reduce future net income and cash flows and negatively impact financial condition. (Applies to all Registrants)

AEP relies on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows or proceeds from the strategic sale of assets and investments, including subsidiaries or portions thereof, such as the announced transaction involving a noncontrolling interest in IMTCo and OHTCo.flows. AEP also relies on access to insurance markets to assist in managing its risk and liability profile. Volatility, increased interest rates 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. In addition, AEP has exposure to international banks, including those in Europe, Canada and Asia. Disruptions in these markets could reduce or restrict the AEP’s ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2024,2025, approximately 8%, 25%23% and 16%15% of the Registrants’ available credit facilities were with European, Canadian, and Asian banks, respectively.

CertainIn the past, certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procureprovide insurance for or to invest in companies, such as AEP, that rely on fossil fuels. The public holds diverse and often conflicting views on the use of fossil fuels. AEP has multiple stakeholders, including our shareholders, customers, associates, federal and state regulatory authorities,authorities and the communities in which AEP operates, and these stakeholders will often have differing priorities and expectations regarding issues related to the use of fossil fuels. Any adverse publicity in connection with AEP’s use of fossil fuels could curtail availability from certain sources of capital. IfAdditionally, sourcescertain ofterms capital forthat AEP aremay reducedbe required to include in its financing agreements and/or expectedarrangements sale proceeds domay not becomebe available,acceptable capitalto costscertain investors, which could increaselimit materially.the Restrictedavailability access to capitalof, or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition. If AEP is not able to access debt or equity at competitive rates or at all,increase the abilitycost toof, finance its operations and implement its strategy and business plan as scheduled could be adversely affected. An inability to access debt and equity may limit AEP’s ability to pursue improvements or acquisitions that it may otherwise rely on for future growth.capital.

Shareholder activism, which can take many forms and arise in a variety of situations, could result in substantial costs and divert management’s and AEP’sthe board’sAEP Board’s attention and resources from AEP’s business. Additionally, such shareholder activism could give rise to perceived uncertainties as to AEP’s future, adversely affect AEP’s relationships with its employees, customers or service providers and make it more difficult to attract and retain qualified personnel. Also, AEP may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AEP’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism.

The credit ratings agencies periodically review AEP’s capital structure and the quality and stability of earnings and cash flows. From time to time, AEP’s financial metrics have approached, and may in the future approach, thresholds designated by the credit rating agencies for potential ratings downgrades. Any negative ratings actions could constrain the capital available to AEP and could limit access to funding for operations. AEP’s business is capital intensive, and AEP is dependent upon the ability to access capital at rates and on terms management determines to be attractive. If AEP’s ability to access capital becomes significantly constrained, AEP’s interest costs will likely increase and that could reduce future net income and cash flows and negatively impact financial condition.

AEP and AEPTCo are holding companies and have no operations of their own. Their ability to meet their financial obligations associated with their indebtedness and to pay dividends is primarily dependent on the earnings and cash flows of their operating subsidiaries, primarily their regulated utilities, and the ability of their subsidiaries to pay dividends to them or repay loans from them. Their subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP or AEPTCo) to provide them with funds for their payment obligations, whether by dividends, distributions or other payments. Payments to AEP or AEPTCo by their subsidiaries are also contingent upon their earnings and business considerations. AEP and AEPTCo indebtedness and dividends are structurally subordinated to all subsidiary indebtedness. Accordingly, restrictions on the ability of AEP’s subsidiaries to pay dividends to AEP and AEPTCo could materially impact the amount of cash flow available to, and received by, AEP and AEPTCo.

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations. Year-to-year comparisons between 20232024 and 20222023 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of ourAEP’s Form 10-K for the fiscal year ended December 31, 2023, which specific discussion is incorporated herein by reference.2024.

The Annual Report on Form 10-K for the year ended December 31, 2025 includes a detailed discussion of risk factors. As of MarchJune 31,30, 2026, there have been no material changes to the risk factors previously disclosed in AEP’s 2025 Annual Report on Form 10-K.

Earnings Attributable to AEP Common Shareholders increaseddecreased from $800$1.2 millionbillion in 2025 to $874$713 million in 2026 primarily due to:

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

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

(a)Represents the earnings (loss) attributable to common shareholders or AEP member, or net income (loss) for registrants with no noncontrolling interest.

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

The electric utility industry is undergoing a historic transformation, fueled by rapid commercialand customer classprojected 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 mechanismsmechanisms, 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. Additionally, several AEP utility subsidiaries have made rate filings with state commissions to establish new tariffs for data centers and other large load customers. 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. TheseAs of March 31, 2026, these tariff proposals have beenwere filed in eight of AEP’s jurisdictions, with four alreadyreceiving approvedapproval byfrom 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 MarchJune 31,30, 2026, there were fourthree pending proposals in Michigan, Oklahoma, TexasOklahoma and Virginia.SWEPCo-Texas. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to advanceconnect large load customers to the grid while also advancing system reliability, resiliency and affordability across its service territory during this period of rapid transformation.territory.

•RFPsRequests for proposals seeking approximately 12,70012,100 MWs of generating capacity.

AEP uses sales volumes by customer class as a way to measure drivers of customer demand. InThrough 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 unusually coldfavorable weather in the first quarterand second quarters of 2025 and unusually warmnormal weather inthrough 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 MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 2025. Load figures are billed and accrued retail sales excluding firm wholesale load.

In March 2026, I&M acquired the Oregon Clean Energy Center (Oregon Plant). TheIn transactionMay reflects2026, APCo acquired the Company’sGrover 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 thethese acquisitionacquisitions:

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.portfolio, Ifwhich approved,was theapproved in May 2026. The combustion turbines would beare projected to be online by the end of 2028.

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 proposes to acquire the Sycamore Plant to provide capacity and energy to I&M Indiana retail and FERC wholesale customers. Also in April 2026, I&M filed an application with the IURC in late April seeking a CPCN for acquisition and development through a PSA of the Sycamore Plant. Through the application, I&M also seeks approval of the estimated project costs,costs proposedand associated ratemaking and accounting treatment, and an alternative regulatory plan.treatment. A final order from the IURC is expected in December 2026.

Significant Approved Renewable Generation and Storage Filings

AEP received regulatory approvalsapproval from various state regulatory commissions to acquire approximately 1,024884 MWs of owned renewable generation and storage facilities, totaling approximately $2.6$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 approvalscommissions for 1,067924 MWs of renewable PPAs. The recently enacted OBBBA legislation is not expected to affect the eligibility of these generation facilities for federal tax incentives. The following table summarizes regulatory approvals received for active renewable projects that are not yet in service as of MarchJune 31,30, 2026:

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

(a)Five wind resources selected totaling 574 MWs from the 2024 RFP havewere already been submittedcontracted 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 applications with the IURC for regulatory approval ofseveral additional resourcesprojects fromselected through the 2024 RFP in the second half of 2026.