AEP Texas Inc.
For the period ended Dec 31, 2025. Filed Feb 12, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 12, 2026
AEP$126.53-0.2%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-13.
0000004904-25-000027
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsSystem Transmission Lines and Facility SitingCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-12.
0000004904-26-000013
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsSystem Transmission Lines and Facility SitingThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 533 previous paragraphs and 553 current paragraphs.
222 unchanged; 140 reworded; 181 added; 163 removed; 8 previous and 10 current paragraphs rearranged.
Tables are not compared: 42 previous and 45 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (181)
Current report
•Customer Service - Industry-best customer experience.
Current report
•Operational Excellence - World-class asset performance.
Current report
•Financial Strength - Strong financial discipline.
Current report
•A decrease in operating expense due to the Federal EPA’s revised CCR rule which resulted in higher operating expenses in 2024.
Current report
•An increase in operating expenses recorded in 2025 due to an impairment of in-process internal use software development costs.
Current report
(c) Represents an adjustment to the estimated loss on the sale of AEP OnSite Partners as a result of the contractual working capital true-up.
Current report
(d) Represents the reduction in regulatory assets for OVEC-related purchased power costs as a result of approved legislation in Ohio in April 2025.
Current report
(e) Represents the impact of the FERC NOLC Order for years 2021-2024.
Current report
(f) Represents an impairment of in-process internal use software development costs.
Current report
(f)Represents a provision for revenue refunds on certain capitalized costs associated with the Turk Plant.
Current report
(i)Represents the impact of the Federal EPA Revised CCR Rule.
Current report
ELECTRIC INDUSTRY TRANSFORMATION
Current report
The electric utility industry is undergoing a historic transformation, fueled by rapid commercial customer class 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 the system peak demand by 2030 across its diversified service territory, with especially strong projected growth in Indiana, Ohio, Oklahoma and Texas. To meet this accelerating demand, AEP outlined a $72 billion, five year capital plan focused on strengthening transmission infrastructure, adding new generation resources to serve both existing customers and large forecasted 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.
Current report
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. These proposals have been filed in eight of AEP’s jurisdictions, with four already approved by state commissions. AEP is actively engaging with regulators, policymakers, RTOs, customers and suppliers to advance system reliability, resiliency and affordability across its service territories during this period of rapid transformation.
Current report
Additionally, AEP continues to secure resources to support forecasted load requirements in its regulated jurisdictions including:
Current report
•The addition of 2.2 GWs of owned generating capacity in 2025.
Current report
•Securing additional turbines for gas-fired turbine capacity.
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•RFPs seeking approximately 12,700 MWs of generating capacity.
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•Long-term transmission construction partnership with a major U.S.-based infrastructure services company.
Current report
Large Load/Data Center Tariffs
Current report
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 90% of their contracted demand. In practice, these provisions reduce risks around the build out of large load infrastructure on existing customers, promoting stability and affordability. The table below provides a summary of the status of these new data center and large load tariffs.
Current report
(a)Both the pending and the approved tariffs include certain requirements for cash, or cash related instruments, as deposits.
Current report
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 way that supports business development in Texas while minimizing 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.
Current report
The PUCT is currently drafting rules through multiple active dockets related to large load interconnection standards, net-metering arrangements for co-location, large load forecasting criteria, large load reliability/demand reduction and transmission cost allocation review to implement SB 6. The rulemaking projects are on various timelines, with final adoptions planned throughout 2026. AEP Texas has signed Letters of Agreement for an incremental 36 gigawatts of load by 2030. As the PUCT finalizes its SB 6 rulemaking efforts, AEP Texas expects improved clarity and certainty around the timing and the amount of additional load connection in ERCOT.
Current report
PJM Capacity Market Reform
Current report
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 alternative (FRR) in which load-serving entities self-supply their generation through owned or contracted resources. All AEP East Companies other than AEP Ohio utilize the FRR alternative.
Current report
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 Board of Directors of PJM issued a decision letter initiating changes to PJM’s capacity market and interconnection processes.
Current report
As direct participants in the PJM capacity market, these reforms have the potential to materially impact AEP’s competitive retail operations and could materially alter OPCo’s cost allocations to retail customers.
Current report
AEP will continue to engage constructively with governors, regulators, PJM, and state and federal policymakers to support reforms that strengthen grid reliability, enable economic growth, and provide transparent, durable investment signals for utilities and investors. Management will continue to monitor activity within PJM and cannot predict the ultimate impact of these early-stage capacity market reform efforts or whether the FRR alternative will be impacted. If changes to PJM auction rules affect AEP’s existing or prospective customer contracts or generation development strategy, it could affect future results of operations.
Current report
New Generation Resources
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Acquired Generation Facilities
Current report
During 2025, PSO acquired four power generation facilities to strengthen its portfolio and enhance reliability. Additionally, in the fourth quarter of 2025, APCo acquired the Top Hat Wind Facility and SWEPCo acquired the Wagon Wheel Wind Facility. These transactions reflect the company’s focus on securing necessary generation to meet future customer demand. See “Acquisitions” section of Note 7 for additional information. The table below summarizes these acquisitions:
Current report
Pending Natural Gas Generation
Current report
In February 2025, I&M filed an application with the IURC to acquire the Oregon Generation Plant (Oregon), an 870 MW combined-cycle power generation facility located near Toledo, Ohio. In April 2025, I&M submitted a FERC 203 application for the acquisition and received approval in October 2025. In August 2025, I&M reached a unanimous settlement in the filing submitted to the IURC with intervening parties approving the acquisition of the Oregon facility and cost recovery. In November 2025, the IURC issued an order granting a CPCN to I&M for its acquisition of the Oregon facility. I&M expects to close on the transaction in the first quarter of 2026.
Current report
In January 2026, the IURC issued a separate order approving the settlement agreement in I&M’s Indiana Expedited Generation Resource (EGR) Plan filing. This order approving the settlement agreement allows I&M to seek expedited IURC approval of future proposed PPAs, capacity purchase agreements (CPAs) and owned generation resources to serve I&M’s increasing customer load and to implement deferral accounting for the generation resources that are approved by the IURC through the EGR Plan process.
Current report
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. If approved, the combustion turbines would be projected to be online by the end of 2028.
Current report
(a)APCo has one wind project under construction.
Current report
(b)PSO has one wind project and one solar project under construction.
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(a)RFP was negotiated and filed for regulatory approval in September 2025.
Current report
(b)Five wind resources selected totaling 574 MWs from the 2024 RFP have already been submitted and approved by the IURC. I&M expects to file applications with the IURC for regulatory approval of additional resources from the 2024 RFP in 2026.
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Removed paragraphs (163)
Previous report
•Delivering industry leading customer service.
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•Operational excellence.
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•Strong financial discipline that drives value for customers and investors.
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AEP is at the forefront of the energy industry’s transformation. AEP’s core strategy is focused on three pillars: 1) reinvestment in core assets, 2) investment in growth opportunities and 3) acquisition of new assets. Highlights of AEP’s strategy include:
Previous report
•The announcement of a five-year, $54 billion capital investment plan that continues to build the energy grid of the future.
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•Adding more than 20,000 MWs of diverse generation resources through 2034 to support resource adequacy, resiliency, affordability and the increasing customer demand for power driven by data processors and economic development.
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•Building a culture of accountability and operational excellence to effectively support regulated operations and enhance customer service.
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•Maintaining a strong balance sheet and achieving our financial targets.
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•Unfavorable regulatory decisions in Texas, West Virginia and at FERC in 2023.
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•A loss on the sale of the competitive contracted renewables portfolio in 2023.
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•An increase in severance expenses and pension settlement expenses resulting from the voluntary severance program announced in April 2024.
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RECENT DEVELOPMENTS AND TRANSACTIONS
Previous report
Noncontrolling Interest in OHTCo and IMTCo (Applies to AEP and AEPTCo)
Previous report
In January 2025, AEP announced a partnership between nonaffiliated entities to acquire a 19.9% indirect noncontrolling interest in OHTCo and IMTCo for $2.82 billion. Net proceeds will be used to help finance AEP’s $54 billion capital plan for 2025-2029, announced in November 2024, driven by transmission and distribution infrastructure upgrades and new generation to support anticipated load growth. The transaction is subject to FERC approval and clearance from the Committee on Foreign Investment in the United States. AEP expects to close on the transaction in the second half of 2025. If the transaction does not close, it could reduce expected future cash flows and impact financial condition.
Previous report
Acquisition of the Diversion Wind Farm
Previous report
In December 2024, SWEPCo acquired 100% of the equity interests in Diversion Wind Energy, LLC, the owner of Diversion wind farm. The Diversion wind farm is a newly constructed 201 MW wind facility located in Baylor County, Texas and was placed in service in December 2024. Output from Diversion serves FERC wholesale load and retail customers in Arkansas and Louisiana. SWEPCo’s Louisiana jurisdictional share of the Diversion revenue requirement, net of PTC benefit, is recoverable through an authorized rider until the amounts are reflected in base rates. Recovery of the Arkansas portion of the Diversion revenue requirement is expected to begin in 2026 through base rates. See the “Diversion Wind Farm” section of Note 7 for additional information.
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Disposition of AEP Onsite Partners
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In May 2024, AEP signed an agreement to sell AEP OnSite Partners to a nonaffiliated third-party. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions. In September 2024, AEP completed the sale to a nonaffiliated third-party and received cash proceeds of approximately $318 million, net of taxes and transaction costs. The proceeds were used to pay down short-term debt. See the “Disposition of AEP OnSite Partners” section of Note 7 for additional information.
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CCR Rule Revisions
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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 as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land. 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. See “CCR Rule” section in Environmental Issues below for additional information.
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The Registrants have made rate filings with state commissions to transition to stand-alone treatment of NOLCs in retail rate making. The Registrants completed the transition in Tennessee, West Virginia and Virginia prior to 2024 and in Michigan in July 2024. In the most recent KPCo, I&M (Indiana jurisdiction), PSO and SWEPCo base rate cases, the companies filed to transition to stand-alone rate making which was contingent upon a supportive PLR from the IRS.
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In the second quarter of 2024, requests seeking to establish a recovery mechanism for these regulatory assets were filed in Indiana, Oklahoma and Texas. Certain intervenors in each jurisdiction have challenged the recovery or have proposed ratemaking treatment that would offset the recovery of the regulatory assets. In the fourth quarter of 2024, hearings on the merits were held in Indiana and Oklahoma. In January 2025, a second hearing on the merits in Oklahoma was held. A hearing is scheduled for the first quarter of 2025 in Texas.
Previous report
Voluntary Severance Program
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In April 2024, management announced a voluntary severance program designed to achieve a reduction in the size of AEP’s workforce. Approximately 7,400 of AEP’s 16,800 employees were eligible to participate in the program. Approximately 1,000 employees chose to take the voluntary severance package and substantially all terminated employment in July 2024. The severance program provides two weeks of base pay for every year of service with a minimum of four weeks and a maximum of 52 weeks of base pay. Certain positions impacted by the voluntary severance program have been and will continue to be refilled to maintain safe, effective and efficient operations. Net savings from the program will help offset increasing operating expenses and high interest costs in order to keep electricity costs affordable for customers. AEP recorded a $122 million pretax expense in the second quarter of 2024 related to this voluntary severance program. The Registrants paid $118 million of the severance benefits in the second half of 2024. In addition, AEP also recognized a settlement charge of $90 million in 2024 due to the remeasurement of pension obligations driven by the voluntary severance program. AEP will seek recovery for the portion of the expense related to regulated operations. See Note 14 - Voluntary Severance Program for additional information.
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(b)Forecasted percentage change for the year ending December 31, 2025 compared to the year ended December 31, 2024.
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(c)The commercial sales growth is primarily due to new data processor loads and economic development.
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Large Load and Data Center Tariffs
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In July 2024, I&M submitted an application to the IURC to modify its Industrial Power Tariff to incorporate terms and conditions of service that would apply to large load customers with a load, individually or in the aggregate, greater than 150 MW. Among other things, the proposal aimed to extend the duration of electric service agreements (ESAs), implement higher minimum demand charges compared to current tariff provisions and address changes in contract capacity commitments and termination of service.
Previous report
In November 2024, I&M, the Indiana Office of Utility Consumer Counselor and all intervening parties submitted a unanimous joint settlement agreement resolving all issues. The settlement agreement included terms that lowered the threshold for individual customer loads to 70 MW, reduced the minimum contract term to 12 years plus the load ramp period not to exceed 5 years, revised how a customer’s minimum bill would be calculated and revised terms and conditions associated with contract capacity commitments and termination of service. A hearing was held and the parties submitted a joint proposed order in December 2024. I&M anticipates an IURC decision in 2025.
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In May 2024, OPCo submitted an application to the PUCO to establish new tariffs for data centers and mobile data centers that enter new retail service contracts after the tariff's effective date. Among other things, the proposal aimed to extend the duration of ESAs and implement higher minimum demand charges compared to current tariffs. In October 2024, intervening parties representing data centers and certain other parties presented a stipulation endorsing the application with certain adjustments, including broadening the tariff's applicability to all large loads (not limited to data centers) that meet specified criteria, as well as reducing the proposed minimum demand charges.
Previous report
Subsequently, in October 2024, OPCo, along with the PUCO Staff, the Ohio Consumers Counsel, and additional parties, filed a separate stipulation suggesting the approval of the application with modifications. This stipulation recommended retaining the application’s proposal to apply the tariff only to data center customers and it proposed setting minimum demand charges that were higher than those proposed in the October 2024 stipulation but lower than those in the original application. Hearings were held in December 2024 and January 2025. OPCo anticipates a PUCO decision in 2025.
Previous report
New Generation to Support Reliability
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(a)APCo issued notice to proceed for the construction of all 344 MWs of wind capacity.
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(b)PSO has issued notices to proceed for the construction of three wind facilities and one solar facility for a combined total capacity of 742 MWs. These facilities are part of the approved projects contemplated within PSO’s 893 MWs of total new renewable generation.
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Natural Gas Generation
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In June 2024, PSO entered into a PSA to acquire a 795 MW combined-cycle power generation facility located in Oklahoma. The acquisition is subject to OCC pre-approval including the approval of a rider to allow asset recovery prior to the inclusion in base rates in a future rate case. In January 2025, intervenors and the OCC staff filed testimony. While the OCC staff testified that PSO established the need for the acquisition and the Oklahoma Attorney General agreed PSO considered reasonable alternatives, other recommendations included requesting additional analysis on the requirement to consider reasonable alternatives and recommending future cost caps and performance guarantees. PSO filed rebuttal testimony in January 2025 and a hearing with the OCC is scheduled to occur in March 2025. Subject to obtaining the required approvals from FERC and the OCC, PSO expects to close on the transaction by June 2025.
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(a)RFP is seeking 1,500 MW of SPP accredited capacity and associated energy through an all-source solicitation.
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(b)RFP is seeking wind, solar, stand-alone battery energy storage systems and Renewable Energy Certificates.
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(c)RFP seeks up to 4,000 MW (cumulatively) from intermittent (wind, solar), non-intermittent (dispatchable), and emerging technology resources.
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(a)In January 2025, I&M terminated a 481 MW and a 600 MW capacity purchase agreement.
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Reworded paragraphs (140)
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•Approximately 225,000 circuit miles of distribution lines that deliver electricity to 5.6 million customers.
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•Approximately 252,000 circuit miles of distribution lines.
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•Approximately 40,000 circuit miles of transmission lines, including approximately 2,100 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.
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•Approximately 38,000 circuit miles of transmission lines, including approximately 2,000 circuit miles of 765 kV lines.
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•Approximately 23,000 MWs of regulated owned generating capacity as of December 31, 2024, one of the largest complements of generation in the United States.
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•Approximately 25,000 MWs of regulated owned generating capacity as of December 31, 2025.
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AEP is committed to executing its strategy to provide customers with reliable, affordable power. AEP’s vision is focused on six core principles:
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AEP is committed to executing its strategy to improve customers’ lives with reliable, affordable power. AEP’s mission is to put the customer first and is focused on six core principles:
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•Providing a safe and secure workplace for our engaged, trained and developed employees.
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•Employee Commitment - Safe and secure workplace; engaged, trained and developed employees.
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•Environmental respect through creative sustainable energy solutions.
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•Environmental Respect - Creative sustainable energy solutions.
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•Regulatory and legislative integrity that achieves balanced regulatory outcomes and provides trusted industry leadership.
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•Regulatory & Legislative Integrity - Balanced regulatory outcomes; Trusted industry leadership.
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Earnings Attributable to AEP Common Shareholders increased from $2.2 billion in 2023 to $3.0 billion in 2024 primarily due to:
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Earnings Attributable to AEP Common Shareholders increased from $3.0 billion in 2024 to $3.6 billion in 2025 primarily due to:
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•A revenue refund provision related to SWEPCo’s 2012 Texas Base Rate Case and the Turk Plant.
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•A revenue refund provision recorded in 2024 associated with the Turk Plant and SWEPCo’s 2012 Texas Base Rate Case.
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•An increase in operating expenses due to the Federal EPA’s revised CCR rule finalized in May 2024.
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•A decrease in operating expenses due to the voluntary severance program that occurred in the second quarter of 2024.
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•A favorable impact from the receipt of PLRs in 2024 related to the treatment of NOLCs in retail rate making. See “NOLCs in Retail Jurisdictions - IRS PLRs” section below for additional information.
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•The favorable impact from the receipt of PLRs in 2024 related to the treatment of NOLCs in retail ratemaking. See “NOLCs in Retail Jurisdictions - IRS PLRs” section below for additional information.
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AEP reports its financial results in accordance with GAAP by using earnings (loss) attributable to AEP common shareholders as stated above. AEP supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures including operating earnings. Operating earnings, which could differ from GAAP earnings, exclude certain gains and losses and other specified items, including mark-to-market adjustments from commodity hedging activities and other items as set forth in the reconciliation below. Management believes these are not indicative of AEP's ongoing performance.
Current wording
AEP reports its financial results in accordance with GAAP by using earnings (loss) attributable to AEP common shareholders as stated above. AEP supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures including operating earnings. Operating earnings, which could differ from GAAP earnings, exclude certain gains and losses and other specified items, including mark-to-market adjustments from commodity hedging activities and other items as set forth in the reconciliation below. Management believes these items are not indicative of AEP's ongoing performance.
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(c) Represents the impact of the remeasurement of excess ADIT in Arkansas and Michigan.
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(c)Represents the impact of the remeasurement of Excess ADIT in Arkansas and Michigan as a result of the denial of SWEPCo's request regarding the Turk Plant by the APSC and the approved treatment of stand-alone NOLCs by the MPSC.
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(d) Represents the impact of receiving IRS PLRs related to NOLCs in retail rate making on I&M, PSO and SWEPCo. Amount includes a reduction in excess ADIT and activity related to prior periods.
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(d)Represents the impact of receiving IRS PLRs related to NOLCs in retail ratemaking on I&M, PSO and SWEPCo. Amount includes a reduction in Excess ADIT and activity related to prior periods.
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(e) Represents the impact of a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
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(e)Represents the impact of a disallowance recorded at SWEPCo on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
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(g) Represents the loss on the sale of AEP OnSite Partners.
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(g)Represents the loss on the sale of AEP OnSite Partners.
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(h) Represents employee severance charges and pension settlement expenses.
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(h)Represents employee severance charges and pension settlement expenses.
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(j) Represents an estimated loss contingency related to a previously disclosed SEC investigation which is non-deductible for tax purposes based on the IRC rules for fines and penalties.
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(j)Represents an estimated loss contingency related to a previously disclosed SEC investigation.
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(k) Represents the impact of the remeasurement of accumulated deferred income taxes as a result of enacted state tax legislation in Arkansas and Louisiana.
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(k)Represents the impact of the remeasurement of ADIT as a result of enacted state tax legislation in Arkansas and Louisiana.
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(c)Represents the impact of the remeasurement of accumulated deferred income taxes - net operating loss carryforward in Virginia and West Virginia.
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(c)Represents the impact of the remeasurement of ADIT - NOLC in Virginia and West Virginia.
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AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2024, AEP experienced an increase in customer demand for power driven by the growth in new data processing loads and economic development in the commercial customer class. AEP currently forecasts continued growth in customer demand in 2025. The percentage change and forecasted percentage change in sales volumes by customer class are shown in the table below.
Current wording
AEP uses sales volumes by customer class as a way to measure drivers of customer demand. In 2025, AEP experienced an increase in customer demand for power driven primarily by new data processing loads coming online in 2025 in the commercial customer class and favorable weather and marginal growth in the residential class. The table below shows the percentage change in sales volume by customer class.
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(a)Percentage change for the year ended December 31, 2024 as compared to the year ended December 31, 2023.
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(a)Percentage change for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Load figures are billed retail sales excluding firm wholesale load.
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The growth of AEP’s regulated generation portfolio reflects the company’s commitment to meet increasing customer demand for power while balancing cost and reliability.
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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.
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In December 2024, SWEPCo filed an application for a Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT for the 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 Power Plant. If approved, the projects will help SWEPCo address increasing SPP capacity requirements. SWEPCo estimates the combined capital cost of these projects is approximately $723 million and the projects would be placed in service between November 2027 and May 2028.
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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. Regulatory proceedings in all three jurisdictions are underway. If approved, the projects will help SWEPCo address increasing SPP capacity requirements. SWEPCo estimates the combined capital cost of these projects is approximately $723 million and the projects would be placed in service between December 2027 and May 2028.
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AEP has received regulatory approvals from various state regulatory commissions to acquire approximately 2,303 MWs of owned renewable generation facilities, totaling approximately $5.5 billion. The estimated cost of these facilities are included in the Budgeted Capital Expenditures disclosure included in the Financial Condition section below. In addition, AEP has received regulatory approvals for 637 MWs of renewable PPAs. The following table summarizes regulatory approvals received for active renewable projects as of December 31, 2024:
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AEP received regulatory approvals from various state regulatory commissions to acquire approximately 1,285 MWs of owned renewable generation facilities, totaling approximately $3.6 billion. The Financial Condition section below includes the estimated cost of these facilities in the Budgeted Capital Expenditures. In addition, AEP received regulatory approvals for 1,067 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 December 31, 2025:
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FERC 2021 PJM and SPP Transmission Formula Rate Challenge
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In June 2025, the FERC issued two orders, partially reversing its January 2024 decisions on the basis of IRS PLRs accepted into the record, and concluding that the accelerated depreciation-related NOLC adjustments should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. As a result of the June 2025 FERC orders, the Registrants recognized revenues, with interest, attributable to accelerated depreciation-related NOLCs included in transmission formula rates for years 2021 through 2025 and reduced Excess ADIT regulatory liabilities. The impact of the orders resulted in a $499 million increase in Earnings Attributable to AEP Common Shareholders in the second quarter of 2025. See the table below and the “FERC 2021 PJM and SPP Transmission Formula Rate Challenge” section of Note 4 for additional information.
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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 rate making basis should be included in rate base and should also be included in the computation of Excess ADIT regulatory liabilities to be refunded to customers. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below:
Current wording
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. Based on this conclusion, I&M, PSO and SWEPCo recognized regulatory assets related to revenue requirement amounts to be collected from customers, reduced Excess ADIT regulatory liabilities and recorded favorable impacts to net income in the first quarter of 2024 as shown in the table below:
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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. Through December 31, 2024, AEP has recognized NOLC regulatory assets of $93 million.
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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 December 31, 2025, AEP has NOLC regulatory assets of $108 million on its balance sheet.
Previous wording
In November 2024, AEP executed a purchase agreement to acquire 100 MWs of solid oxide fuel cells with an option to acquire up to one gigawatt in total by the end of 2025. AEP, through its utility subsidiaries, is offering data centers and other large customers this custom solution to support their growing energy needs while grid infrastructure enhancements are completed to accommodate demand. Through the date of this filing OPCo has signed multiple contracts for electricity service from fuel cells with customers and is filing those contracts with the PUCO for approval. See “AEP Development Services (Applies to OPCo)” section of Note 18 for additional information.
Current wording
In November 2024, AEP executed a purchase agreement to acquire 100 MWs of solid oxide fuel cells with an option to acquire up to one gigawatt in total by the end of 2025. AEP, through its subsidiaries, offers data centers and other large customers this custom solution to support their growing energy needs while it completes grid infrastructure enhancements to accommodate demand. By the end of the first quarter of 2025, OPCo had signed two contracts totaling approximately 98 MWs for electricity service from fuel cells. In February 2025, OPCo requested PUCO approval of those two contracts. The PUCO approved the contracts in May 2025.
Previous wording
In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, 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 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from these claims, including any future enforcement or litigation resulting from any determinations of noncompliance by the Federal EPA with various aspects of the CCR Rule consistent with the Gavin Denial. The owners of the Gavin Power Station have also sought indemnification for landowner claims for property damage allegedly caused by modifications to the FAR. 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. In January 2024, Gavin Power LLC also filed a complaint with the United States District Court for the Southern District of Ohio, alleging various violations of the Administrative Procedure Act and asserting that the Federal EPA, through its prior inaction, has waived and is estopped from raising certain objections raised in the Gavin Denial. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
Current wording
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 EPA 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 6 for additional information.
Previous wording
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 result from the change in Presidential administrations.
Current wording
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.
Previous wording
The rules and environmental control requirements discussed below will have a material impact on AEP’s operations. As of December 31, 2024, AEP owned generating capacity of approximately 23,200 MWs, of which approximately 10,700 MWs were coal-fired. In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules 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 ensuring compliance with all of the rules while meeting AEP’s obligations to provide reliable and affordable electricity.
Current wording
The rules and environmental control requirements discussed below will have a material impact on AEP’s operations. As of December 31, 2025, AEP owned generating capacity of approximately 25,400 MWs, of which approximately 10,700 MWs were coal-fired. In April 2024, the Federal EPA announced four major new rules directed at fossil-fuel electric generation facilities. Management continues to evaluate the impacts of these rules 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.
Previous wording
The costs of complying with new rules 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 and (g) other factors.
Current wording
The costs of complying with new rules 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) policy changes implemented by the Presidential administration and (h) other factors.
Previous wording
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (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. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.
Current wording
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.
Previous wording
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 to include additional requirements, resulting in further emission reductions to ensure that the new standard will be met. Areas around some of AEP’s generating facilities may be deemed nonattainment, which may require those facilities to install additional pollution controls or to implement operational constraints. The nonattainment designations by the Federal EPA and the subsequent SIP revisions by the affected states will take some time to complete; therefore, management cannot reasonably estimate the impact on AEP’s operations, cash flows, net income or financial condition.
Current wording
If the rule is not vacated, areas around some of AEP’s generating facilities may be deemed nonattainment, which may require those facilities to install additional pollution controls or to implement operational constraints. Any nonattainment designations by the Federal EPA and the subsequent SIP revisions by affected states will take time to finalize and complete. Management cannot reasonably estimate any impacts on AEP’s operations, cash flows, net income or financial condition.
Previous wording
The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require 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. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs. Petitions for review of the final rule revisions were filed in the U.S. Court of Appeals for the District of Columbia Circuit. In early 2018, the Federal EPA announced plans to revisit aspects of the final rule raised by petitioners in petitions for administrative reconsideration, and the court granted the Federal EPA’s motion to hold the litigation in abeyance.
Current wording
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.
Previous wording
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. The proposed rule was published in the Federal Register in October 2024, initiating a public comment period ending November 14, 2024. The deadline for the Federal EPA to take final action on the Texas SIP is May 30, 2025.
Current wording
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. Management will continue to monitor the litigation and cannot predict the outcome.
Previous wording
In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. AEP has been able to meet the requirements of the revised rule over the first few years of implementation, and is evaluating its compliance options for later years, when the budgets are further reduced.
Current wording
In January 2021, the Federal EPA finalized a revised CSAPR, which substantially reduced the ozone season NOX budgets for several states, including states where AEP operates, beginning in ozone season 2021. AEP met the requirements of the revised rule over the first few years of implementation, and is evaluating its compliance options for future years, when the budgets are further reduced.
Previous wording
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. The Federal EPA disapproved interstate transport SIPs submitted by additional states soon thereafter. Disapproval of the SIPs provided the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. As a result of several separate legal challenges brought by states and industry parties in various federal courts, implementation of the FIP has been stayed in all of the states in which AEP operates. In October 2024, the Federal EPA issued a final rule to administratively stay the effectiveness of the Good Neighbor Plan’s requirements for all sources covered by that rule as promulgated where an administrative stay was not already in place. The administrative stay of the Good Neighbor Plan’s effectiveness for power plants and other industrial facilities in each of the 23 states will remain in place until the Supreme Court lifts its order staying enforcement of the Good Neighbor Plan, other courts lift any judicial orders staying the SIP disapproval action as to the state, and the Federal EPA takes subsequent rulemaking action consistent with any judicial rulings on the merits. Additionally, in February 2025, the Federal EPA filed a motion with the court seeking to hold the legal challenges related to the Good Neighbor Plan in abeyance for 60 days, to allow the new administration time to review the rule. Management will continue to monitor the outcome of this litigation and the development of SIPs for any potential impact to operations.
Current wording
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. The Federal EPA disapproved interstate transport SIPs submitted by additional states soon thereafter. Disapproval of the SIPs provided the Federal EPA with authority to impose a FIP for those states, replacing the SIPs that were disapproved. In August 2023, a FIP (the Good Neighbor Plan) went into effect that further revised the ozone season NOX budgets under the existing CSAPR program in states to which the FIP applies. The FIP has since been administratively stayed pending the Supreme Court lifting its order staying enforcement of the Good Neighbor Plan, other courts lifting any judicial orders staying the SIP disapproval action as to the state, 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.
Previous wording
In April 2024, the Federal EPA issued a revised MATS rule for power plants. The rule 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. Management is evaluating the impacts of the rule, but does not anticipate any significant challenges complying with the rule.
Current wording
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 June 2025, the Federal EPA proposed to repeal the 2024 MATS rule and revert to the 2012 MATS rule emission standards. Management does not anticipate any significant challenges complying with the 2024 MATS rule, should the proposed repeal not be finalized.
Showing the first 40 of 140 pairs. Open the source sections for the rest.
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•The favorable impact from the receipt of the June 2025 FERC order related to the treatment of NOLCs in transmission formula rates.
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•Capacity purchase agreements to satisfy capacity reserve margins to serve customers.
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(b)Primarily relates to a $384 million remeasurement of Excess ADIT regulatory liabilities, partially offset by $71 million of tax expense on favorable pretax income.
Current report — wording carried from elsewhere
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 to include additional requirements, resulting in further emission reductions to meet the new standard. 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.
Current report — wording carried from elsewhere
Heating Degree Days and Cooling Degree Days
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•A $14 million decrease due to a disallowance recorded on the remaining net book value of the Dolet Hills Power Station as a result of an LPSC approved settlement agreement in April 2024.
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•Depreciation and Amortization expenses decreased $59 million primarily due to the following:
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•A $14 million increase due to an increase in pretax book income.
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•An $18 million increase in equity earnings.
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Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.
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(i) Represents the impact of the Federal EPA’s revised CCR Rule.
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
(d)Western Region cooling degree days are calculated on a 70 degree temperature base.
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•Interest Expense increased $20 million primarily due to higher long-term debt balances and interest rates.
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Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:
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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. AEP continues monitoring the current bank environment and any impacts thereof. AEP was not materially impacted by these conditions during the year ended December 31, 2024.
Previous report — wording carried elsewhere
These increases in cash used were partially offset by:
Previous report — wording carried elsewhere
These decreases in cash were partially offset by: