AEPAmerican Electric Power
AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. 10-K, Item 1
- Headquarters
- Columbus, OH
- CEO
- William Fehrman
- Next results
- around Feb 11, 2027
21 paragraphs in Risk Factors of the 10-K filed Feb 12, 2026 with nothing like them in the 10-K filed Feb 13, 2025. Quoted exactly. Paragraphs that were only edited are under 10-K change.
Compared with the Risk Factors in the latest 10-K of the other 30 Utilities companies: a paragraph with at least half its words the same at another company is called similar, and the companies are listed under it. A paragraph most of them have is marked boilerplate. No line means no other company has one like it. This counts text; it does not say how serious a risk is.
The business and capital investment plans of AEP depend, in part, on the continued growth and viability of data centers and large load customers interconnecting with the AEP System. (Applies to all Registrants)
AEP is experiencing current and projected load demands that exceed historical experience, creating a business need for new power generating resources and transmission facilities. Much of this demand is driven by interconnecting with and providing power to data centers and other large load customers to serve an increasingly digital economy and to support AI. The business and capital investment plans of AEP are focused on meeting these current and projected needs. If these increased demands for electricity do not occur as projected or are not sustained as projected, for any reason, it could affect AEP’s financial condition.
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Meeting the significant increase in electricity demand from new data centers and other large‑load customers will require substantial investment in new generation and transmission facilities. These projects may require levels of capital that exceed historical utility financing needs, and the ability of the capital markets to supply sufficient funding for large‑scale infrastructure expansion is uncertain. AEP’s ability to undertake these capital‑intensive projects depends in part on continued access to debt and equity markets. If capital markets experience reduced liquidity, constrained capacity for utility issuances, or diminished investor appetite for long‑duration infrastructure investments, AEP may be unable to obtain the financing required to support these projects. Even if capital is available, it may only be obtainable at significantly higher cost due to market conditions or competition for capital among utilities and other sectors. Any inability to secure adequate financing could delay or prevent the construction of required facilities, impair AEP’s ability to serve its customers, and adversely affect future net income, cash flows and financial condition.
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•If regulated utility earnings exceed the return established by a relevant commission, that commission could reduce future rates;
•Any legislation, regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost or establishment of a regulatory liability.
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Risks from cybersecurity and physical threats to energy infrastructure are increasing. Threat actors, including sophisticated nation-state actors and criminal groups, exploit potential vulnerabilities in the electric utility industry, grid infrastructure and other energy infrastructures. Attacks and disruptions, which could involve physical, cyber and hybrid targeting of physical and cyber assets, are increasingly sophisticated and dynamic. The increased implementation of, and reliance on, information technologies and networks to manage business operations, including the operation of technical systems, as well as AEP’s use of numerous vendors and suppliers, create additional points of vulnerability that could be, and in certain instances have been, exploited by malicious threat actors. Several U.S. government agencies have warned that the energy sector and its supply chains are subject to increasing risks of physical attacks, ransomware attacks and cybersecurity threats, and that the risks may escalate during periods of heightened geopolitical tensions. In addition, the rapid evolution and increased adoption of AI technologies may intensify AEP’s cybersecurity risks.
Similar paragraph at 1 of 30 other Utilities companies: EXCA security breach of AEP’s physical assets or information systems, or those of AEP’s competitors, vendors, business partners and interconnected entities (including RTOs) could materially impact AEP by, among other things, impairing the availability of electricity transmitted and distributed by AEP and/or the reliability of generation, transmission and distribution systems, damaging grid infrastructure, interrupting critical business functions, impairing the availability of vendor services and materials that AEP relies on to maintain its operations, or by leading to the theft or inappropriate release of certain types of information, including critical infrastructure information, system data and architecture, sensitive customer, vendor, or employee data, or other confidential data.
Similar paragraph at 1 of 30 other Utilities companies: EXCAEP has not identified any cybersecurity incidents that have materially affected or are reasonably likely to materially affect its business strategy, results of operation or financial condition.
If a material physical or cybersecurity breach or disruption were to occur, AEP’s reputation could be negatively affected, customer confidence in AEP could be diminished and AEP could be subject to legal claims, regulatory exposure, loss of revenues, and increased costs, including infrastructure repairs or operations shutdown, all of which could materially affect AEP’s financial condition and materially damage its business reputation. Moreover, the amount and scope of insurance maintained against losses resulting from any such security breaches or disruptions may not be sufficient to cover losses or otherwise adequately compensate for any resulting business disruptions. The continued increase in federal and state regulatory requirements related to cybersecurity and evolving threat actor-capabilities could require changes to measures currently undertaken by AEP or to its business operations and could adversely affect its financial condition.
Similar paragraph at 1 of 30 other Utilities companies: EXCRead in the 10-K ↗
Changes in U.S. or foreign trade policies, including the imposition of tariffs and other protectionist trade measures, and other factors beyond AEP’s control may adversely impact future net income and cash flows and financial condition.
Similar paragraph at 1 of 30 other Utilities companies: CNPExecutive actions have been taken and additional measures proposed that are intended to alter the U.S. approach to international trade policy, the terms of certain existing bilateral or multi‐lateral trade agreements and trading arrangements with foreign countries. Such changes to U.S. international trade policy, and any retaliatory trade measures that foreign governments may take in response, including the imposition of tariffs, sanctions, export or import controls, or other measures that restrict international trade, or the threat of such actions, could result in additional increases in the cost of certain goods, services and cost of capital and exacerbate supply chain issues. In addition, related geopolitical and domestic political developments, such as existing and potential trade wars, uncertainty regarding changes in trade policy, and other events beyond AEP’s control, have increased and may continue to increase levels of political and economic unpredictability globally and the volatility of global financial markets. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.
Similar paragraph at 1 of 30 other Utilities companies: CNPRead in the 10-K ↗
Difficulties in sustaining leadership continuity could negatively impact AEP’s business and financial condition. The ability to maintain strong leadership relies on effective succession planning, and gaps in preparing or transitioning individuals into critical roles may impact performance.
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AEP is exposed to changes in the price and availability of purchased power and fuel (including the cost to procure coal and gas) and the price and availability to transport fuel.
•AEP is exposed to changes in the price and availability of fuel, including coal, natural gas and uranium, as existing contracts for the supply of such fuel end or are not honored.
•The inability to procure fuel at costs that are economical could cause AEP to retire generating capacity prior to the end of its useful life.
•AEP is exposed to changes in the price and availability of emission allowances.
•AEP is exposed to changes in the price and availability of diesel, the primary fuel used in transporting coal by barge.
While AEP typically recovers such fuel-related expenses pursuant to rate recovery mechanisms in regulated jurisdictions, the failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition.
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mitigation efforts, regulatory recovery risk, litigation risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.
Similar paragraph at 1 of 30 other Utilities companies: XELRead in the 10-K ↗
2 more
Adverse outcomes in AEP’s material legal proceedings could materially and adversely affect AEP’s results of operations and financial condition. (Applies to all Registrants)
Similar paragraph at 1 of 30 other Utilities companies: VSTRead in the 10-K ↗
The impact of new laws, regulations and policies and the related interpretations, as well as changes in enforcement practices or
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New in the latest 10-Q
66 paragraphs in the 10-Q filed Oct 28, 2026 with nothing like them in the 10-Q filed Jul 30, 2026 (at least half the words must differ; new numbers alone do not count). Quoted exactly, grouped by the item heading above them. This is text that changed, not a judgement of how serious it is.
10-Q
AEP T&D Services AEP T&D Services, LLC, an unregulated subsidiary of AEP, is a specialized infrastructure services organization that delivers engineering, project management, procurement, and construction services for electric transmission, distribution and related utility infrastructure.
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DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
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New, modified, repealed or suspended federal, state or local legislation, regulations, policies or executive actions that alter the regulatory framework; delay or prevent approvals or permits; affect approved or planned investments; or prevent timely recovery of costs and investments.
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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AEP continues to convert large load interest across its service territory into signed customer financial commitments. These commitments, primarily from data processing and other energy-intensive customers, are expected to support sales growth, expand the customer base and improve utilization of AEP’s generation, transmission and distribution systems. New data processing load contributed to commercial and industrial sales growth during 2026, demonstrating that large load additions have begun to contribute to operating results.
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AEP is leveraging its generation portfolio, transmission network and infrastructure execution capabilities to support committed and forecasted customer demand, including:
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• Long-term agreements with leading infrastructure services companies to provide engineering, project management and construction support for planned transmission infrastructure expansion.
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The AEP East Companies are members of PJM. Utilities in PJM can meet their capacity obligations by either: (a) participating in capacity auctions administered by PJM, or (b) via the Fixed Resource Requirement (FRR) alternative in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than OPCo utilize the FRR alternative.
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In January 2026, the White House, all thirteen state governors from across the PJM footprint, and senior federal energy officials jointly released a Statement of Principles. This Statement of Principles is designed to increase capacity available in the PJM market for large load customers and to ensure the costs of those resources are paid for by the large load customers to protect existing customer affordability. The Statement of Principles directs PJM to hold a one-time Reliability Backstop Auction, accelerate capacity market reforms in response to unprecedented data center load growth, and align costs associated with new capacity coming into the market with the large load customers necessitating the resources. Subsequently, in a proceeding pending since 2025, the PJM Board of Managers issued a decision letter initiating changes to PJM’s capacity market and interconnection processes.
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In September 2026, the FERC accepted the RBP proposal for filing but suspended its effectiveness until February 28, 2027, subject to refund and further proceedings concerning cost allocation, transmission-owner exit obligations and load-serving entity collateral requirements. To expedite implementation, the FERC encouraged PJM to submit a revised proposal by October 29, 2026. PJM indicated that it intends to submit a revised proposal.
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In October 2026, the FERC accepted PJM’s definition of Large Load and its Large Load Registry, effective October 12, 2026, and directed a compliance filing within 30 days. The registry covers existing and future large loads, with information-reporting obligations on load-serving entities and supporting information from electric distributors where needed. AEP’s operating companies, including both FRR and non-FRR entities are subject to the Large Load Registry reporting requirement. However, the FERC rejected the remainder of the IRAS filing, including the proposed curtailment framework, Bring Your Own New Capacity requirements and related capacity-market provisions. The FERC identified jurisdictional and other deficiencies and provided guidance for a revised proposal should PJM choose to refile. The IRAS rejection also eliminated the proposed FRR procurement restrictions described above, including the June 1, 2027 cutoff for determining the quantity of existing generation capacity available to serve new large loads.
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In August 2026, the Governor of Texas directed the PUCT and ERCOT to conduct a comprehensive verification of all Batch Zero loads and an audit of data center projects 25 MW and above advancing through ERCOT's interconnection process before any additional projects move forward. Following the governor’s direction, ERCOT announced that it would not meet an August 2026 deadline associated with the Batch Zero interconnection study process and received a good-cause exception from the PUCT regarding Batch Zero schedule and implementation requirements. ERCOT has currently paused Batch Zero classification and study activity and stated it will not authorize large loads to energize until verification is complete.
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Company Plant Name Fuel Type Location Acquisition Date Net Maximum Capacity ────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────────── (in MWs) I&M Oregon Natural Gas Oregon, OH March 2026 870 APCo Grover Hill Wind Paulding County, OH May 2026 143 AGR Wolf Hills Natural Gas Bristol, VA August 2026 263 I&M Big Sandy Peaker Natural Gas Kenova, WV August 2026 318 PSO Lazbuddie Wind Parmer and Castro Counties, TX August 2026 265 Total Acquired Generation Facilities 1,859
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In May 2026, APCo filed an application with the Virginia SCC seeking approval for two new solar PSAs including Skycrest (155 MWs) located in Jay County, Indiana, anticipated to be placed in service in December 2028, and Riverstart V (100 MWs) located in Randolph County, Indiana, anticipated to be placed in service in August 2028. The petition also included request for approval of two wind PPA extensions consisting of Beech Ridge (101 MWs) with an 8-year extension starting in 2030 and Camp Grove (150 MWs) with a 10-year extension starting in 2027.
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In July 2026, I&M filed an application under its Expedited Generation Resource Plan (EGR Plan) requesting approval of amended contractual terms to the previously approved 245 MW Lake Trout Solar Project PSA. A final order is expected in November 2026.
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In September 2026, SWEPCo filed applications for CCNs with the APSC, LPSC and PUCT, seeking regulatory approval for the acquisition of the Brantley Branch project, a 200 MW 6-hour BESS, located in Rusk County, Texas. Regulatory approvals are expected in the third quarter of 2027 and the project is expected to close and come into service in the fourth quarter of 2028.
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In October 2026, KPCo entered into an amended agreement with TeraWulf Inc., for 1 GW of contracted demand. KPCo plans to file an application seeking approval of the agreement and the related generation investments in the fourth quarter of 2026.
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In August 2026, OHTCo, OPCo and an unaffiliated customer executed definitive agreements related to the construction of three 765 kV transmission lines by OHTCo to support the development of a proposed 10.4 GW data center campus in Piketon, Ohio. The three 765 kV transmission lines, each expected to provide approximately 3.2 GWs of incremental transmission capacity, have targeted in-service date goals of December 31, 2028, 2029 and 2030. The initial 800 MWs of load is expected to be served utilizing existing transmission capacity and does not require any additional regulatory approvals.
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For the balance of the approximately 10.4 GW, and subject to applicable regulatory approvals and the terms of the definitive agreements, OHTCo is expected to recover approved transmission-related costs related to the new load through arrangements with OPCo, which will, in turn, recover such amounts from the customer pursuant to a retail service agreement designed to prevent any of the costs of the project from being allocated to other OPCo customers. Under the agreement, the customer is responsible for those costs, including the applicable return, with no allocation of those costs to other OPCo customers.
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The definitive agreements related to the transmission investment to serve the load provide for a base ROE of 11.35%, which may increase to 11.99% or decrease to 10.71% based on the actual project costs as compared to budgeted costs and actual in-service dates as compared to targeted in-service dates for each transmission line, and include payment terms extending for 20 years following the applicable in-service dates. The agreements establish a budget for the project of approximately $5 billion. The Piketon Transmission Project requires regulatory approvals from PJM, the PUCO and the FERC. The equipment purchase agreement currently in effect requires the customer to fully collateralize OHTCo equipment purchases prior to receiving the required regulatory approvals. The ultimate scope, timing, cost recovery mechanisms and economics of the project are subject to regulatory review and approval.
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In October 2026, the KPSC issued an order conditionally approving construction and cost recovery through a rider, subject to WVPSC CPCN approval and receipt of funding related to the June 2026 Department of Energy award. In addition, KPCo is required to provide the KPSC with written notice of any increase to estimated project costs that exceeds 5%. Additionally in October 2026, the WVPSC issued an order approving construction. Cost recovery will be addressed in a future filing. WPCo is required to provide the WVPSC with written notice of any increase to estimated project costs that exceeds 10%.
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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• A $370 million decrease in cash from the Change in Certain Components of Working Capital. This decrease is primarily due to timing of accounts receivable collections and an increase in fuel, materials and supplies driven by higher coal inventory on hand, partially offset by the increase in customer deposits.
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(in billions) ─────────────────────────────────────────────────────────────────────────────────────────────────── Segment 2027-2031 Budgeted Capital Expenditures Vertically Integrated Utilities $ 52.2 Transmission and Distribution Utilities 23.6 AEP Transmission Holdco 18.1 Generation & Marketing 4.4 Corporate and Other 2.1 Total $ 100.4
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(a) Cash dividends declared per AEP common share were $0.95 and $0.93 in 2026 and 2025, respectively.
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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• A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.
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• A $9 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting in March 2026.
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• A $3 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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• A $39 million increase in West Virginia ENEC under-recoveries due to WVPSC orders for final recovery of West Virginia MRBC, Broadband and Vegetation Management under-recovery balances through ENEC rates.
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• A $21 million increase in Virginia consumable expenses that were previously deferred prior to the Virginia SCC approving recovery of these costs through Virginia E-RAC rates starting March 2026.
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• A $14 million increase in Virginia jurisdictional purchased power costs that are not recoverable through the Virginia FAC.
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025
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Upon settlement of the ATM Forward maturing December 2026, the Company will issue three million shares of common stock. However, as the forward price was greater than the average market price of the common shares as of September 30, 2026, the shares were not included in the computation of diluted EPS because to do so would be antidilutive. There were no antidilutive shares outstanding as of September 30, 2025.
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In May 2026, the Companies submitted supplemental testimony that adjusted the original requested annual increase in ENEC rates from a $ 21 million annual increase to a $ 9 million annual decrease. This modification was the result of a revised forecast of ENEC costs for the period September 2026 through August 2027.
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In August 2026, the WVPSC issued an order approving a $ 9 million annual decrease in ENEC rates effective September 1, 2026.
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(a) Amounts represent estimates. The WVPSC may update these estimates prior to securitization bond marketing.
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In August 2026, intervenors submitted testimony recommending a $ 1 million annual increase in base rates based on a recommended 9.325 % ROE. Included in this proposed revenue requirement is a proposed denial of recovery of a $ 9 million regulatory asset related to APCo’s targeted circuits program that was previously approved for deferral by the Virginia SCC. Intervenor testimony also proposed the disallowance of alleged above-market purchased power expense from OVEC.
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In September 2026, Virginia SCC staff issued testimony recommending a $ 6 million annual decrease in base rates based on a recommended 9.65 % ROE, the removal of $ 37 million of vegetation management costs from base rates for recovery through a separate surcharge and modifications to APCo’s forecasted capital expenditures, retirements and accumulated depreciation for 2026 and 2027. For purposes of Virginia retail ratemaking, Virginia SCC staff testimony recommended continued capitalization of certain vegetation management costs impacted by the recent FERC Audit of SWEPCo.
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In September 2026, APCo filed rebuttal testimony supporting a revised annual increase in base rates of $ 16 million. The change in APCo’s proposal is based primarily on the recommended removal of $ 37 million of vegetation management costs to be recovered through a separate rider and $ 12 million of ARO costs that are also recommended to be recovered through a separate rider.
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In October 2026, APCo, Virginia SCC staff and intervening parties entered into a settlement agreement that includes an estimated first year $ 4 million reduction to base revenues and a net $ 0 second year change in base revenues based on a 9.80 % ROE and a capital structure of 50.2 % debt and 49.8 % common equity. The settlement agreement also includes: (a) an agreement for APCo to prospectively recover vegetation management capital and operation and maintenance costs through a separate rate adjustment clause, (b) an agreement for APCo to prospectively recover generation-related ARO costs through a separate rate adjustment clause, (c) approval for APCo to recover $ 8 million of deferred costs related to APCo’s targeted circuits program and (d) authority for APCo to defer PJM ancillary services costs using an $ 11 million band above or below the level approved for recovery in base rates. For purposes of Virginia retail ratemaking, the settlement agreement also provides for continued capitalization of certain vegetation management costs impacted by the recent FERC Audit of SWEPCo. See the “FERC Audit” section below for additional information. A hearing was held in October 2026.
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In August 2026, I&M submitted its earnings test evaluation for the period ended May 2026 with a proposed over-earnings credit to customers through the FAC of $ 66 million. In September 2026, an intervening party submitted testimony agreeing with I&M’s proposed over-earnings credit of $ 66 million for the period ending May 2026. Beginning March 2026 and as approved by the IURC, I&M reflects costs associated with the Oregon Clean Energy Center and other plants approved by the IURC for acquisition under I&M’s Expedited Generation Resource (EGR) Plan either as eligible costs for recovery through existing I&M Indiana riders or in I&M’s ongoing Indiana earnings test evaluation. See the "Oregon Clean Energy Center" and the "Big Sandy Peaker Plant" sections of Note 6. I&M Indiana jurisdictional over-earnings up to the amount of revenue from large load customers are now accumulated in a separate regulatory liability for refund to customers over a time period to be determined in a future proceeding at the IURC. As of September 30, 2026, the balance of this regulatory liability was $ 97 million. Any over-earnings that exceed the amount of revenue from large load customers will continue to be credited to customers through the FAC. See the “2026 Indiana Base Rate Case” section below for discussion of I&M’s proposed Reduce-and-Freeze mechanism (RAF). The IURC is expected to issue an order in the fourth quarter of 2026.
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In August 2026, in accordance with a settlement agreement previously approved by the IURC and consistent with HEA 1002, I&M submitted a base rate filing with the IURC based on a MYRP for the forecasted years 2027 through 2029. The proposed MYRP includes a RAF rate mechanism with an overall $ 42 million decrease in I&M Indiana base and rider rates based on a 10.1 % ROE and a capital structure of 48.8 % debt and 51.2 % equity. I&M’s MYRP proposes to freeze base rates and most rider rates, with limited exceptions primarily related to large load customers. The RAF will repurpose I&M’s existing Indiana Earnings Test. Under the RAF, I&M will continue to measure its actual earnings compared to its authorized earnings and record a regulatory liability for I&M Indiana jurisdictional earnings that exceed I&M’s authorized net operating income (NOI) and ROE thresholds. During the MYRP, I&M requested accounting authority to recover its increasing cost of service and earn up to its IURC-authorized Indiana jurisdictional NOI and ROE by amortizing existing regulatory liabilities or establishing a regulatory asset for recovery in a future MYRP proceeding.
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I&M’s MYRP and authorized ROE will be subject to specific performance metrics and PIMs ordered by the IURC.
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I&M’s Indiana base rate update filing also describes I&M’s intent to submit a Subsequent License Renewal Application (SLRA) filing with the Nuclear Regulatory Commission (NRC) in the first quarter of 2027 that will request an extension of the current licenses of Cook Plant Units 1 and 2 from 2034 and 2037 as currently authorized, to 2054 and 2057, respectively. I&M is requesting recovery of related costs expected to be incurred during the MYRP and proposed depreciation rates reflect this anticipated license extension.
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Under the SPP OATT, costs of sponsor-funded transmission upgrades may be recovered, in part, from SPP customers whose transmission service is dependent upon capacity enabled by the upgrades. In 2016, SPP billed transmission service customers, including PSO and SWEPCo, for upgrade costs incurred since 2008. SPP then credited the qualifying transmission owners, including SWEPCo, for the use of these upgrades. In July 2026, as a result of a FERC order, the amounts billed relating to the period 2008 to 2015 were required to be refunded. In the third quarter of 2026, PSO recognized a net favorable impact of approximately $ 12 million while SWEPCo had no net impact related to this matter. SPP is currently analyzing impacts related to costs of sponsor-funded transmission upgrades for the period subsequent to 2015. Based on the information currently available, management does not believe a loss is probable and cannot determine a range of potential losses, if any, that is reasonably possible of occurring.
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During the third quarter of 2026, management concluded that I&M’s $ 782 million agreement to purchase gas- and steam-powered turbines met the definition of an unconditional purchase obligation in accordance with the accounting guidance for “Commitments.” Remaining spend on the contract is as follows: $ 31 million through 2026, $ 497 million in 2027, $ 145 million in 2028 and $ 31 million in 2030.
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During the third quarter of 2026, management concluded that PSO’s $ 349 million agreement to purchase gas- and steam-powered turbines met the definition of an unconditional purchase obligation in accordance with the accounting guidance for “Commitments.” Remaining spend on the contract is as follows: $ 54 million through 2026, $ 129 million in 2027 and $ 9 million in 2028 and 2029.
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In August 2026, AGR completed the acquisition of 100 % of the equity interests in Wolf Hills Energy, LLC, the owner of the Wolf Hills Energy Facility (Wolf Hills), a natural gas-fired, simple-cycle electric generation facility located in Bristol, Virginia. Wolf Hills, a competitive generation asset operating within the PJM market, began commercial operations in 2001. As AGR is not a regulated electric utility, Wolf Hills is not currently subject to regulatory rate recovery approvals.
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Supplies (MWs) (in millions) Oregon Plant OH Natural Gas 870 $ 918 $35 $5 $16 $9
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(c) Includes three million shares with a final maturity in December 2026 and expected proceeds of $ 374 million and three million shares with a final maturity in July 2028 and expected proceeds of $ 310 million.
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In October 2026, AEP made capital contributions of $ 450 million and $ 210 million to AEP Texas and OPCo, respectively.
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AEP's contract liabilities primarily relate to advance payments received under contracts for the procurement of long-lead-time transmission and distribution equipment and related construction services, as well as services provided under joint use agreements for utility poles. During 2026, AEP T&D Services entered into additional transmission and distribution equipment arrangements under which customers provided consideration in advance of performance. Revenue associated with these arrangements is recognized over time as the related performance obligations are satisfied. AEP T&D Services had contract liabilities of $ 197 million and $ 37 million as of September 30, 2026 and December 31, 2025, respectively. Contract liabilities for the Registrant Subsidiaries were not material as of September 30, 2026 and December 31, 2025.
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Other information
On October 23, 2026, American Electric Power Company, Inc. (“Company”) entered into a Settlement, Release of All Claims, and Noncompetition Agreement (“Agreement”) with Alicia Knapp, former President Nuclear Development of the Company, in connection with Ms. Knapp’s previously disclosed separation from the Company. The Agreement supersedes the severance arrangements described in the Company's Current Report on Form 8-K filed on September 30, 2026.
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Pursuant to the Agreement, Ms. Knapp will receive $4,342,662.00, less applicable withholdings required by law, subject to Ms. Knapp’s execution and non-revocation of the Agreement, which includes a general release, and continued compliance with the restrictive covenants and other obligations set forth therein. The amount was agreed upon with Ms. Knapp after considering certain financial consequences associated with her transition to employment with the Company and the timing of her subsequent separation. The payments and benefits under the Agreement are in lieu of any payments or benefits that Ms. Knapp otherwise may have been entitled to receive under the Company's Executive Severance Plan or General Severance Plan, and Ms. Knapp has waived any rights to benefits under those plans.
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The foregoing description of the Agreement is qualified in its entirety by reference to the Agreement, a copy of which will be filed with the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2026.
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The 10-Q's risk factors against the 10-K
Item 1A of the 10-Q filed Oct 28, 2026 against Item 1A of the 10-K filed Feb 12, 2026.
A 10-Q repeats only the risks that changed, so a 10-K paragraph that is missing from it is not counted as removed.
Added is a paragraph with nothing like it in the 10-K, Reworded a sentence that is in both with several words changed,
Quiet changes a sentence in both where one to four words changed and one is a hedge or a modal
(cut words struck through, new words highlighted and underlined).
Text on the page, not a score; each links to the filing at sec.gov.
What the 10-Q itself says about its risk factors:
Read in the 10-Q ↗
The Annual Report on Form 10-K for the year ended December 31, 2025 includes a detailed discussion of risk factors. As of September 30, 2026, there have been no material changes to the risk factors previously disclosed in AEP’s 2025 Annual Report on Form 10-K.
1 paragraph in the 10-Q's Item 1A, and none of them adds, rewords or quietly edits a paragraph of the 10-K's.
Work on AEP in a spreadsheet:
Excel workbook (a sheet per section, ten years by column, charts, links to the filings) ·
CSV.
For a Google Sheet that stays up to date, paste =IMPORTDATA("https://tickdelta.com/company/AEP/export.csv") into a cell.