American Electric Power Co Inc: Form 10-K for the period ended Dec 31, 2024

GENERAL

Overview and Description of Major Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The member companies of AEP have contractual, financial and other business relationships with the other member companies, such as participation in AEP savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The member companies of AEP also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2024, the subsidiaries of AEP had a total of 16,330 employees. Because it is a holding company rather than an operating company, AEP has no employees.

Summary information related to AEP subsidiary operating companies as of December 31, 2024 is shown in the table below:

(a) KGPCo does not own any generating facilities and purchases electric power from APCo for distribution to its customers.

(b) OPCo purchases energy and capacity at auction to serve generation service customers who have not switched to a competitive generation supplier.

(c) AEPTCo is a holding company for the State Transcos. Five State Transcos are members of PJM and two State Transcos are members of SPP. Neither AEPTCo nor its subsidiaries have any employees. Instead, AEPSC and certain AEP utility subsidiaries provide services to these entities.

Service Company Subsidiary

AEPSC is a service company subsidiary that provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to AEP subsidiaries. The executive officers of AEP and certain of the executive officers of its public utility subsidiaries are employees of AEPSC. As of December 31, 2024, AEPSC had 6,237 employees.

Principal Industries Served

The following table illustrates the principal industries and wholesale electric markets served by AEP’s public utility subsidiaries.

(a) Primarily includes data centers and cryptocurrency operations.

Public Utility Subsidiaries by Jurisdiction

The following table illustrates certain regulatory information with respect to the jurisdictions in which the public utility subsidiaries of AEP operate:

(a) Identifies the predominant current authorized ROE, and may not include other, less significant, permitted recovery. Actual ROE varies from authorized ROE.

(b) In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OHTCo transmission formula rates effective February 2022, reducing OHTCo’s authorized ROE to 9.85%.

(c) In February 2022, as part of the 2020 Texas Base Rate Case, SWEPCo filed a motion for rehearing with the PUCT alleging several errors in the final order, which included a challenge of the approved ROE. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order. See “2020 Texas Base Rate Case” section of Note 4 for additional information.

CLASSES OF SERVICE

AEP and subsidiaries recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. AEP’s subsidiaries within the Vertically Integrated Utilities, Transmission and Distribution Utilities, AEP Transmission Holdco and Generation & Marketing segments derive revenue from the following sources: Retail Revenues, Wholesale and Competitive Retail Revenues, Other Revenues from Contracts with Customers and Alternative Revenues. For further information relating to the sources of revenue for the Registrants, see Note 20 - Revenues from Contracts with Customers for additional information.

FINANCING

General

AEP subsidiaries generally use short-term debt to finance working capital needs. Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term funding. In recent history, short-term funding needs have been provided for by cash from operations, AEP’s commercial paper program and term loan issuances. Funds are made available to subsidiaries under the AEP corporate borrowing program. Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity. Sources of long-term funding include issuance of long-term debt, long-term asset securitizations, leasing agreements, hybrid securities or common stock. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for these types of facilities, including a maximum debt-to-total capitalization test. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of its major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $100 million, would cause an event of default under the credit agreements. As of December 31, 2024, AEP was in compliance with its debt covenants. With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the applicable agreement. A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control, solid and hazardous waste disposal and other environmental matters, and are subject to zoning and other regulation by local authorities. The current and proposed environmental laws and regulations discussed below will have an impact on AEP’s operations. Management continues to monitor developments in these regulations and evaluate the economic feasibility and refine cost estimates for compliance. 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. For additional information on the laws and regulations discussed below, see “Environmental Issues” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Clean Air Act Requirements (CAA)

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.

Clean Water Act Requirements

The Federal EPA’s ELG rule for generating facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are to be implemented through each facility’s wastewater discharge permit. In April 2024, the Federal EPA finalized further revisions to the ELG rule that establish a zero liquid discharge standard for FGD wastewater, bottom ash transport water, and managed combustion residual leachate, as well as more stringent discharge limits for unmanaged combustion residual leachate. The revised rule provides a new compliance alternative that would eliminate the need to install zero liquid discharge systems for facilities that comply with the 2020 rule’s control technology requirements and commit by December 31, 2025 to retire by 2034. Management is evaluating the compliance alternatives in the rule, taking into consideration the requirements of the other new rules and their combined impacts to operations. Several appeals have been filed with various federal courts challenging the 2024 ELG rule. SWEPCo has also challenged the rule, by filing a joint appeal with a utility trade association in which AEP participates. The various appeals have been consolidated before the United States Court of Appeals for the Eighth Circuit. SWEPCo and the utility trade association filed a motion to stay the rule during the litigation. In October 2024, the court denied the motion. Management cannot predict the outcome of the litigation.

Coal Ash Regulation

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

In April 2024, the Federal EPA finalized revisions to the CCR Rule to expand the scope of the rule to include inactive impoundments at inactive facilities (“legacy CCR surface impoundments”) as well as to establish requirements for currently exempt solid waste management units that involve the direct placement of CCR on the land (“CCR management units”). The Federal EPA is requiring that owners and operators of legacy surface impoundments comply with all of the existing CCR Rule requirements applicable to inactive CCR surface impoundments at active facilities, except for the location restrictions and liner design criteria. The rule establishes compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within five years after the effective date of the final rule. The rule requires evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. Closure may be accomplished by applying an impermeable cover system over the CCR material (“closure in place”) or the CCR material may be excavated and placed in a compliant landfill (“closure by removal”). Groundwater monitoring and other analysis over the next three years will provide additional information on the planned closure method. AEP evaluated the applicability of the rule to current and former plant sites and recorded incremental ARO of $674 million in the second quarter of 2024 based on initial cost estimates primarily reflecting compliance with the rule through closure in place and future groundwater monitoring requirements pursuant to the revised CCR Rule.

As further groundwater monitoring and other analysis is performed, management expects to refine the assumptions and underlying cost estimates used in recording the ARO. These refinements may include, but are not limited to, changes in the expected method of closure, changes in estimated quantities of CCR at each site, the identification of new CCR management units, among other items. These future changes could have a material impact on the ARO and materially reduce future net income and cash flows and further impact financial condition.

Climate Change, CO2 Regulation and Energy Policy

In April 2024, the Administrator of the Federal EPA signed new GHG standards and guidelines for new and existing fossil-fuel fired sources. The rule relies on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and carbon capture and sequestration or limited utilization to reduce CO2 emissions from new gas turbines. The rule also offers early retirement of coal plants in lieu of carbon capture and storage as an alternative means of compliance. A number of parties filed petitions for review of the rule in the U.S. Court of Appeals for the D.C. Circuit. AEP is in the early stages of evaluating and identifying the best strategy for complying with this rule while ensuring the adequacy of resources to meet customer needs. The Federal EPA’s new GHG rule is directed at the fossil-fuel fired electric utility industry and could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites. See “The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation” section of Note 6 for additional information.

Electric Industry Transformation

The electric utility industry is in the midst of an historic transformation, driven by large load growth in the commercial customer class from data processing loads, changing customer needs, evolving public policies, stakeholder demands, demographics, competitive offerings, technologies and commodity prices.

AEP is committed to providing reliable affordable power to its customers. To achieve this, AEP and its subsidiaries routinely meet with state regulators and key stakeholders to understand their needs for both dispatchable and renewable generation resources. This process evaluates, amongst other things, future supply and demand fundamentals, the economic aspects of investments, grid reliability and resilience, regulations and evolving RTO requirements, the advancement of generation technologies, and market impacts and constraints. As part of the regulatory process, AEP routinely submits IRPs in various regulatory jurisdictions to address future generation needs. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers.

As of December 31, 2024, AEP’s generating capacity included owned and PPA capacity of approximately 23,200 MWs and 5,300 MWs, respectively. The graph below summarizes AEP’s generating capacity by resource type for the years 1999, 2005 and 2024:

(a) Energy Efficiency/Demand Response represents avoided capacity rather than physical assets.

Corporate Governance

In response to environmental issues and in connection with its assessment of AEP’s strategic plan, the Board of Directors continually reviews the risks posed by new environmental rules and requirements that could alter the retirement date of coal-fired generation assets. The Board of Directors is informed of new environmental regulations and proposed environmental regulations or legislation that would significantly affect AEP. In addition, the Board holds extended meetings twice a year to provide extra time for a more robust review of the Company’s strategy, including discussions about carbon and carbon risk. The Board’s Committee on Directors and Corporate Governance oversees AEP’s annual Corporate Sustainability Report, which includes information about AEP’s environmental, social, governance and financial performance.

HUMAN CAPITAL MANAGEMENT

Attracting, developing and retaining high-performing employees with the skills and experience needed to serve our customers efficiently and effectively is crucial to AEP’s growth and competitiveness and is central to our long-term strategy. AEP invests in employees and continues to build a high performance and inclusive culture that inspires leadership, encourages innovative thinking and welcomes everyone.

The following table shows AEP’s number of employees by subsidiary as of December 31, 2024:

(a) Primarily relates to AEP Energy employees.

Of AEP’s 16,330 employees, less than 1% are Traditionalists (born before 1946), approximately 12% are Baby Boomers (born 1946-1964), approximately 37% are Generation X (born 1965-1980), approximately 42% are Millennials (born 1981-1996) and less than 9% are Generation Z (born after 1996). As of December 31, 2024, women comprised approximately 20% of AEP’s total workforce, approximately 21% of AEP’s total workforce was represented by racially or ethnically diverse employees and approximately 25% of AEP’s total workforce was represented by labor unions.

Safety

Safety is integral to our culture and is one of AEP’s core values. AEP is dedicated to ensuring the safety of our employees, contractors, customers and the communities we serve. AEP has policies, procedures, programs, training and initiatives in place to help ensure a safety conscious work environment. We are committed to fundamentally embed layers of protection in the work we do. This includes focusing our efforts to prevent serious injuries and fatalities, strengthening pre-job briefing effectiveness, learning from safety incidents, providing appropriate training and education and improving proactive safety initiatives and data analysis to identify and address potential performance gaps.

AEP’s employee Days Away, Restricted and Transferred (DART) rate and Total Recordable Incident Rate (TRIR) increased in 2024. A DART event is an event that results in one or more lost days, one or more restricted days, or results in an employee transferring to a different job within the company. The DART rate is a mathematical calculation (number of DART events multiplied by 200,000 and divided by total YTD hours worked) that describes the number of injuries per 100 full-time employees annually. A recordable event is a work-related event that results in death, days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness or a significant injury or illness diagnosed by a physician or other licensed health care professional. TRIR is a mathematical calculation (number of recordable events multiplied by 200,000 and divided by total year to date hours worked) that describes the number of incidents per 100 full-time employees annually. In response to these challenges, AEP is recommitting to fundamental principles of excellence by integrating human performance fundamentals into our operational practices to ensure a safer work environment for all.

Culture and Inclusion

At AEP, we believe in doing the right thing every time for our customers and each other and that culture serves as the foundation for our success. We recognize that an engaged, collaborative and inclusive workforce helps us better serve our employees, customers, suppliers and other key stakeholders. AEP views a culture as a core business value that is centered on performance, accountability and developing our employees. As a strategic priority, our commitment to culture and inclusion is guided by three principles:

• Ensuring leaders are held accountable for fostering an inclusive environment and culture.
• Promoting an inclusive culture where all employees can thrive.
• Supporting the communities we serve so they will prosper.

AEP’s culture and inclusion progress is measured through our annual Employee Voice Survey. The Employee Voice Survey is an opportunity for employees to provide feedback about their experience at AEP. It also serves as a means for the company to understand how we can foster a workplace focused on performance, accountability, efficiency, and customer orientation. 2024 marks our eleventh consecutive year of formally surveying employees about their experience at AEP.

Training and Professional Development

Attracting, developing, and retaining high-performing employees with the skills and experience needed to serve our customers efficiently and effectively is crucial to AEP’s growth and long-term strategy. At AEP, we are preparing our workforce for the future by providing opportunities to learn new skills and engaging higher education institutions to better prepare the next generation of workers. AEP offers co-op and internship programs in partnership with high schools, technical/vocational schools and colleges across our 11-state service territory. AEP also provides a broad range of training and assistance that supports lifelong learning and development. This includes operational skills training, professional training, leadership development, educational assistance, ongoing performance coaching, and other forms of training that offer developmental pathways for employees.

Compensation and Benefits

AEP is committed to the well-being of our employees, and we offer programs to foster employee financial security, physical and emotional health, and social connectedness. We provide market-competitive compensation and benefits, including medical and dental coverage, life insurance, and well-being programs that support our employees and their families. Nearly all AEP employees participate in an annual incentive program that rewards individual performance and achievement of business goals, fostering a high-performance culture. AEP also offers paid time off in the form of vacation, holidays, sick time, and parental leave.

BUSINESS SEGMENTS

AEP’s Reportable Segments

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

• Vertically Integrated Utilities
• Transmission and Distribution Utilities
• AEP Transmission Holdco
• Generation & Marketing

The remainder of AEP’s activities is presented as Corporate and Other, which is not considered a reportable segment. See Note 9 - Business Segments for additional information on AEP’s segments.

Seasonality

The consumption and delivery of electric power is generally seasonal which impacts the results of operations of AEP’s reportable segments. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters. In addition, AEP has historically sold and delivered less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish AEP’s results of operations. Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities

As of December 31, 2024, AEP’s vertically integrated public utility subsidiaries owned approximately 23,200 MWs of generation. See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

Fuel Supply

The following table shows the owned and leased generation sources by type (including wind purchase agreements), on an actual net generation (MWhs) basis, used by the Vertically Integrated Utilities:

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An increase/decrease in one or more generation types relative to previous years reflects changes in resource mix and price changes in one or more fuel commodity sources relative to the pricing of other fuel commodity sources. AEP’s overall 2024 fossil fuel costs for the Vertically Integrated Utilities increased 3.2% on a dollar per MMBtu basis from 2023.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal under a combination of purchasing arrangements, including long-term contracts, and spot agreements with various producers and marketers. Coal consumption increased 12.7% in 2024 from 2023.

Management projects that the Vertically Integrated Utilities will be able to secure and transport coal of adequate quality and quantities to operate their coal fired units. As of December 31, 2024, through subsidiaries, AEP owns, leases or controls 2,934 railcars, 296 barges, 4 towboats and a coal handling terminal with approximately 18 million tons of annual capacity to move and store coal for use in AEP generating facilities. AEP will procure additional railcar and barge/towboat capacity as needed based on demand.

Although coal prices remained stable for all of 2024 the market price for coal is greater than historical prices (excluding 2021 and 2022), due to the higher cost incurred by the suppliers to mine coal over the last few years. Coal prices may see a fluctuation in the next few years as utilities begin to reenter the market as high inventories decline and as forecasted demand for electricity increases. AEP’s strategy for purchasing coal includes maintaining a target inventory level by layering in supplies over time to help with reducing price volatility. The price paid for coal delivered in 2024 decreased approximately 3.5% from 2023 mainly due to the completion of higher priced coal supply agreements that were agreed to in 2021 and 2022 when coal market pricing was stronger. The decrease in the delivered cost of coal should continue into 2025 as some higher priced agreements ended in 2024. With AEP’s strategy of layering tons into the coal portfolio the prices over the next few years will continue to fluctuate with the coal market.

The following table shows the amount of coal and lignite delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of coal and lignite purchased by the Vertically Integrated Utilities:

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, consumption rates driven by the demand for electric power, unit outages, transportation limitations or delays, space limitations, labor issues, supplier outages and issues and weather conditions, all of which may impact production, consumption or deliveries. As of December 31, 2024 and 2023, the Vertically Integrated Utilities’ coal inventory was approximately 71 days and 82 days of full load burn, respectively. Inventory levels remained high in 2024 due to mild weather conditions and continued low natural gas prices. Management expects inventory levels to remain elevated in 2025 due to many of these same factors. While inventory targets vary by plant and are changed as necessary, the current coal inventory target for the Vertically Integrated Utilities is approximately 35 days of full load burn.

Natural Gas

The Vertically Integrated Utilities consumed approximately 155 billion cubic feet of natural gas during 2024 for generating power. This represents an increase of 6.7% from 2023. Several of AEP’s natural gas-fired units are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. From a natural gas supply perspective, the Vertically Integrated Utilities secure forward month, fixed price baseload supply, prompt month baseload supply, and pursue daily spot market purchases or sales (to balance daily positions). From a natural gas transportation perspective, the Vertically Integrated Utilities utilize firm and interruptible transportation capacity. Furthermore, SWEPCo and PSO utilize firm natural gas storage, which supports price stability and provides additional surety of natural gas supply. AEP’s natural gas supply, transportation and storage transactions are competitively bid and are based on applicable market prices.

The following table shows the amount of natural gas delivered to the Vertically Integrated Utilities’ plants during the past three years and the average delivered price of natural gas purchased by the Vertically Integrated Utilities:

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Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant. I&M has made and will make purchases of uranium in various forms in the spot, short-term, mid-term and long-term markets.

For purposes of the storage of high-level radioactive waste in the form of SNF, I&M completed modifications to its SNF storage pool in the early 1990’s. I&M entered into an agreement to provide for onsite dry cask storage of SNF to permit normal operations to continue. I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis. The year of expiration of each NRC Operating License is 2034 for Unit 1 and 2037 for Unit 2. Management has started the application process for license extensions for both units that would extend Unit 1 and Unit 2 to 2054 and 2057, respectively.

Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of SNF and decommission and decontaminate the plant safely. The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. The most recent decommissioning cost study was completed in 2024. According to that study, stated in 2024 undiscounted dollars, the estimated cost of decommissioning and disposal of low-level radioactive waste was $2.4 billion, with additional ongoing costs of $7 million per year for post decommissioning storage of SNF and an eventual cost of $45 million for the subsequent decommissioning of the SNF storage facility. As of December 31, 2024 and 2023, the total decommissioning trust fund balance for the Cook Plant was approximately $4 billion and $3.5 billion, respectively. The balance of funds available to eventually decommission Cook Plant will differ based on contributions and investment returns. The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

• Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
• Further development of regulatory requirements governing decommissioning.
• Technology available at the time of decommissioning differing significantly from that assumed in studies.
• Availability of nuclear waste disposal facilities.
• Availability of a United States Department of Energy facility for permanent storage of SNF.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections. AEP will seek recovery from customers through regulated rates if actual decommissioning costs exceed projections. See the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies for additional information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. Michigan does not currently have a disposal site for such waste available. I&M cannot predict when such a site may be available. However, the states of Utah and Texas have licensed low-level radioactive waste disposal sites which currently accept low-level radioactive waste from Michigan waste generators. There is currently no set date limiting I&M’s access to either of these facilities. The Cook Plant has a facility onsite designed specifically for the storage of low-level radioactive waste. In the event that low-level radioactive waste disposal facility access becomes unavailable, it can be stored onsite at this facility.

Counterparty Risk Management

The Vertically Integrated Utilities segment also sells power and enters into related energy transactions with wholesale customers and other market participants. As a result, counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions. As of December 31, 2024, counterparties posted approximately $16 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately $201 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

Certain Power Agreements

I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the energy and capacity available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all of its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The UPA will continue in effect until the debt obligations of AEGCo secured by the Rockport Plant have been satisfied and discharged (currently expected to be December 2028).

In April 2021, AEGCo and I&M executed an agreement to purchase 100% of the interests in Rockport Plant, Unit 2 effective at the end of the lease term on December 7, 2022. Prior to the termination of the lease, I&M assigned 30% of the power to KPCo. Beginning December 8, 2022, AEGCo billed 100% of its share of the Rockport Plant to I&M and ceased billing to KPCo. KPCo reached an agreement with I&M, from the end of the lease through May 2023, to buy capacity from Rockport Plant, Unit 2 through the PCA at a rate equal to PJM’s RPM clearing price. See the “Unit Power Agreements” section of Note 17 - Related Party Transactions for additional information.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC. The aggregate equity participation of AEP in OVEC is 43.47%. Parent owns 39.17% and OPCo owns 4.3%. Under the Inter-Company Power Agreement (ICPA), which defines the rights of the owners and sets the power participation ratio of each, the sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. The ICPA terminates in June 2040. The proceeds from charges by OVEC to sponsoring companies under the ICPA based on their power participation ratios are designed to be sufficient for OVEC to meet its operating expenses and fixed costs. OVEC’s Board of Directors, as elected by AEP and nonaffiliated owners, has authorized environmental investments related to their ownership interests, with resulting expenses (including for related debt and interest thereon) included in charges under the ICPA. OVEC financed capital expenditures in excess of $1 billion in connection with flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants through debt issuances, including tax-advantaged debt issuances. Both OVEC generation plants are operating with the environmental controls in-service. See Note 18 - Variable Interest Entities and Equity Method Investments for additional information.

ELECTRIC DELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 – Properties for more information regarding the transmission and distribution lines. Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC. The FERC regulates and approves the rates for both wholesale transmission transactions and wholesale generation contracts. The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, principles, protocols and agreements in place with PJM and SPP, and as approved by the FERC. See Item 1. Business – Vertically Integrated Utilities – Regulation – FERC. As discussed below, some transmission services also are separately sold to nonaffiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service within a specific territory. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA. OPCo, which is a subsidiary in AEP’s Transmission and Distribution Utilities segment that provides transmission service under the PJM OATT, is also a party to the TA. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

Transmission Coordination Agreement and Open Access Transmission Tariff

PSO, SWEPCo and AEPSC are parties to the TCA. Under the TCA, a coordinating committee is charged with the responsibility of: (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the AEP and SPP OATTs filed with the FERC and the rules of the FERC relating to such tariffs. Pursuant to the TCA, PSO, SWEPCo and AEPSC each have responsibility for monitoring and reporting situations or problems that materially affect the reliability of PSO’s and SWEPCo’s transmission systems. The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services as determined by the FERC-approved OATT for the SPP.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of SPP (both FERC-approved RTOs). RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

REGULATION

General

AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions. AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions. I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant. AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of, much of the Energy Policy Act of 2005, which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes. State utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment. Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative. Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers. Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in-service. Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery. Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, management actively pursues strategies to accelerate rate recognition of investments and cash flow. AEP representatives continue to engage state commissioners and legislators on alternative rate-making options to reduce regulatory lag and enhance certainty in the process. These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP’s vertically integrated public utility subsidiaries operate. Several public utility subsidiaries operate in more than one jurisdiction. See Note 4 - Rate Matters for more information regarding pending rate matters.

Arkansas

SWEPCo provides retail electric service in Arkansas at bundled rates approved by the APSC, with rates set on a historical cost-of-service basis and formula rates. Arkansas provides for timely fuel and purchased power cost recovery through respective annual fuel and purchased power recovery mechanisms.

Indiana

I&M provides retail electric service in Indiana at fully bundled rates approved by the IURC, with rates set on a forecasted cost-of-service basis. Indiana generally allows for timely recovery of fuel expenses through a fuel recovery surcharge mechanism. I&M is subject to a semi-annual Indiana jurisdictional earnings test.

Kentucky

KPCo provides retail electric service in Kentucky at bundled rates approved by the KPSC, with rates currently set on a historical cost-of-service basis. Kentucky generally allows for timely recovery of fuel expenses through a fuel recovery surcharge mechanism.

Louisiana

SWEPCo provides retail electric service in Louisiana at bundled rates approved by the LPSC with rates set on a historical cost-of-service basis and formula rates. Louisiana provides for timely fuel and purchased power cost recovery through respective fuel and purchased power recovery mechanisms updated monthly.

Michigan

I&M provides retail electric service in Michigan at both unbundled standard service and open access distribution service rates approved by the MPSC, with rates set on a forecasted cost-of-service basis. Open access distribution service is limited to 10% of I&M’s retail load. Michigan generally allows for timely recovery of fuel expenses, transmission expenses and purchased power expenses through a single surcharge mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a historical cost-of-service basis. Fuel and purchased energy costs are recovered through a fuel adjustment clause.

Tennessee

KGPCo currently provides retail electric service in Tennessee at bundled rates approved by the TPUC. Tennessee generally allows for timely recovery of fuel expenses and purchased power expenses through a surcharge mechanism.

Texas

SWEPCo provides retail electric service in Texas at bundled rates approved by the PUCT with rates set on a historical cost-of-service basis. Texas generally provides for timely fuel and purchased power cost recovery through respective fuel and purchased power recovery mechanisms.

Virginia

APCo currently provides retail electric service in Virginia at unbundled generation and distribution rates approved by the Virginia SCC. Virginia generally allows for timely recovery of fuel expenses through a fuel cost recovery surcharge mechanism. In addition to base rates and fuel cost recovery, APCo is permitted to recover transmission expenses provided at OATT rates based on rates established by the FERC. APCo is subject to a biennial Virginia retail generation and distribution earnings test.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC with rates set on a combined APCo and WPCo cost-of-service basis. West Virginia generally allows for timely recovery of fuel expenses, purchased power expenses and transmission expenses through a single surcharge mechanism.

FERC

The FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates, and AEP has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. In addition, the FERC regulates the sale of power for resale in interstate commerce by: (a) approving contracts for wholesale sales to municipal and cooperative utilities at cost-based rates and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices. AEP’s vertically integrated public utility subsidiaries have market-based rate authority from the FERC, under which much of their wholesale marketing activity takes place. The FERC requires each public utility that owns or controls interstate transmission facilities, directly or through an RTO, to file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. Additionally, the vertically integrated public utility subsidiaries are subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets. AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM. PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over certain issuances of securities of most of AEP’s public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.

COMPETITION

AEP’s vertically integrated public utility subsidiaries primarily generate, transmit and distribute electricity to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories. These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC, and are not subject to competition from other vertically integrated public utilities. Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights that effectively grant the exclusive ability to provide electric service in various municipalities and regions in their service areas.

AEP’s vertically integrated public utility subsidiaries compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil, renewables and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize alternative sources of energy other than electric power. With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they currently maintain a competitive position.

TRANSMISSION AND DISTRIBUTION UTILITIES

GENERAL

This segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power. See Item 2 – Properties, for more information regarding the transmission and distribution lines. Transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories. These sales are made at rates approved by the PUCT for AEP Texas and by the PUCO and the FERC for OPCo. The FERC regulates and approves the rates for wholesale transmission transactions. As discussed below, some transmission services also are separately sold to nonaffiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas. In some cases, these franchises provide the utility with the exclusive right to provide electric service. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC. In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries also provide transmission services for nonaffiliated companies through RTOs.

Transmission Agreement

OPCo owns and operates transmission facilities that are used to provide transmission service under the PJM OATT; OPCo is a party to the TA with other utility subsidiary affiliates. The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM. The TA has been approved by the FERC.

Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO. RTOs operate, plan and control utility transmission assets to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not. AEP Texas is a member of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC. AEP Texas sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) and Distribution Cost Recovery Factor (DCRF) filings. AEP Texas may file interim TCOS and DCRF filings semi-annually to update its rates to reflect changes in its net invested capital. Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service. The cost-of-service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes. Utility commissions periodically adjust rates pursuant to a review of: (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

The FERC regulates rates for transmission of electric power, accounting and other matters. The FERC regulations require AEP to provide open access transmission service at FERC-approved rates, and it has approved cost-based formula transmission rates on file at the FERC. The FERC also regulates unbundled transmission service to retail customers. The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system. The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system. Additionally, the transmission and distribution utility subsidiaries are subject to mandatory reliability standards as set forth by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.

AEP TRANSMISSION HOLDCO

GENERAL

AEPTHCo is a holding company for (a) AEPTCo, which is the direct holding company for the State Transcos and (b) AEP’s Transmission Joint Ventures.

AEPTCo

AEPTCo wholly owns the State Transcos which are independent of, but respectively overlay, the following AEP electric utility operating companies: APCo, I&M, KPCo, OPCo, PSO, SWEPCo and WPCo. The State Transcos develop, own, operate and maintain their respective transmission assets. Individual State Transcos (a) have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, (b) are authorized to submit projects for commission approval in Virginia and (c) have been granted consent to enter into a joint license agreement that will support investment in Tennessee. Assets of the State Transcos interconnect to transmission facilities owned by the aforementioned operating companies and nonaffiliated transmission owners within the footprints of PJM, MISO and SPP. APTCo, IMTCo, KTCo, OHTCo and WVTCo are located within PJM. IMTCo also owns portions of the Greentown station assets located in MISO. OKTCo and SWTCo are located within SPP. SWTCo does not currently own or operate transmission assets.

The State Transcos own, operate, maintain and invest in transmission infrastructure in order to maintain and enhance system integrity and grid reliability, grid security, safety, reduce transmission constraints and facilitate interconnections of new generating resources and new wholesale customers, as well as enhance competitive wholesale electricity markets. A key part of AEP’s business is replacing and upgrading transmission facilities, assets and components of the existing AEP System as needed to maintain reliability. As of December 31, 2024, the State Transcos had $15.4 billion of transmission and other assets in-service, excluding CWIP, with plans to construct approximately $4.7 billion of additional transmission assets through 2027.

In January 2025, AEP announced a partnership between nonaffiliated entities to acquire a 19.9% noncontrolling interest in OHTCo and IMTCo for $2.82 billion. The transaction is subject to FERC approval and clearance from the Committee on Foreign Investment in the United States. See “Noncontrolling Interest in OHTCo and IMTCo” section of Note 21 for additional information.

AEPTHCO JOINT VENTURE INITIATIVES

AEP has established joint ventures with nonaffiliated electric utility companies for the purpose of developing, building and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America (Transmission Joint Ventures). The Transmission Joint Ventures currently include:

(in millions)

(a) ETT is undertaking multiple projects and the completion dates will vary for those projects. ETT’s investment in completed and active projects in ERCOT is expected to be $5.0 billion by 2030. Future projects will be evaluated on a case-by-case basis.

(b) In May 2020, Pioneer received FERC approval authorizing an ROE of 10.02% (10.52% inclusive of the RTO incentive adder of 0.5%). In October 2024, the FERC issued an order reducing the base ROE for MISO Transmission Owners to 9.98% (10.48% inclusive of the RTO incentive adder of 0.5%).

(c) The ROE represents the weighted-average approved ROE based on the costs of two projects developed by Transource Missouri; the $64 million Iatan-Nashua project (10.3%) and the $246 million Sibley-Nebraska City project (11.3%).

(d) AEP owns 86.5% of Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma through its ownership interest in Transource Energy, LLC (Transource). Transource is a joint venture between AEPTHCo and Evergy, Inc. formed to pursue competitive transmission projects. AEPTHCo and Evergy, Inc. own 86.5% and 13.5% of Transource, respectively.

(e) See “Independence Energy Connection Project” section of Note 4 for additional information.

(f) In 2016, Transource Kansas received approval from the FERC authorizing an ROE of 9.8% (10.3% inclusive of the RTO incentive adder of 0.5%) for future competitive transmission projects in SPP. In October 2020, Transource was awarded the Sooner-Wekiwa project by SPP and the project was assigned to Transource Kansas. In November 2020, Transource Kansas was renamed Transource Oklahoma. The project is expected to go in-service in November 2025.

(g) In October 2022, Transource Energy’s North Delta A proposal was awarded by the New Jersey Board of Public Utilities. In December 2023, the North Delta project was expanded with additional scope and approved by the PJM Board of Managers. The project was renamed Bramah Station and is expected to go in-service in 2027. The project was originally expected to go in-service in 2029.

Transource Energy, and its subsidiaries Transource Missouri, Transource West Virginia, Transource Maryland, Transource Pennsylvania and Transource Oklahoma are consolidated joint ventures by AEP. All other joint ventures in the table above are not consolidated by AEP. AEP’s joint ventures do not have employees. Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners. In 2024, approximately 502 AEPSC employees and 302 operating company employees provided service to one or more joint ventures.

REGULATION

The State Transcos and the Transmission Joint Ventures located outside of ERCOT establish transmission rates annually through forward-looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols. The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently-incurred and reasonably calculated.

The State Transcos’ and the Transmission Joint Ventures’ (where applicable) rates are included in the respective OATT for PJM and SPP. An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system. The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners in annual rate base filings with the FERC. The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe. The formula rates also include a true-up calculation for the previous year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken. Additionally, the State Transcos are subject to mandatory reliability standards promulgated by the NERC, with the approval of the FERC, which standards protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. Management monitors pending matters before the FERC, including inquiries and challenges related to ROEs and transmission formula rates, that have the potential to reduce AEP’s future transmission formula rates and/or the transmission ROE methodology.

In the annual formula rate filings described above, the State Transcos in aggregate filed formula rate base totals of $11.4 billion, $10.7 billion and $9.9 billion for 2024, 2023 and 2022, respectively. The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.9 billion, $1.8 billion and $1.7 billion for 2024, 2023 and 2022, respectively.

The rates of ETT, which is located in ERCOT, are determined by the PUCT. ETT sets its rates through a combination of base rate cases and interim Transmission Cost of Services (TCOS) filings. ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

GENERATION & MARKETING

GENERAL

The AEP Generation & Marketing segment consists of a retail supply business, a wholesale energy trading and marketing business and the rights to Cardinal Plant Unit 1’s power and capacity through 2028. AEP Generation & Marketing previously included AEP OnSite Partners prior to its sale in September 2024 and AEP Renewables prior to its sale in August 2023.

The retail energy supply business provides electricity and/or natural gas to residential, commercial and industrial customers in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 987,000 customer accounts as of December 31, 2024.

The wholesale trading and marketing business transacts within RTOs to provide supply to customers, manage pricing risk or otherwise provide service to fulfill contractual obligations. Additionally in certain instances this business procures physical electricity from identified sources, including renewable generation, when providing service to customers. When adapting to meet the demands of customers’ changing needs or in response to changing circumstances of electricity markets and generation sources, this business executes transactions and modifies contracts as applicable to maximize value and mitigate pricing and delivery risk when fulfilling contractual obligations to its customers.

This segment also includes rights to Cardinal Plant Unit 1’s power and capacity through 2028 through a PPA with a nonaffiliated electric cooperative.

COMPETITION

The AEP Generation & Marketing segment subsidiaries face competition for the sale of available power, capacity and ancillary services. The principal factors of impact are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. Other factors impacting competitiveness include environmental regulation, transmission congestion or transportation constraints at or near generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at generation facilities. Technology advancements, increased demand for clean energy, changing consumer behaviors, low-priced and abundant natural gas, and regulatory and public policy reforms are among the catalysts for transformation within the industry that impact competition for AEP’s Generation & Marketing segment.

AEP Generation & Marketing’s retail energy supply business operates in jurisdictions that each establish laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Severe load and market volatility, sustained low market volatility and maturing competitive environments can adversely affect this business.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions. As of December 31, 2024, counterparties posted approximately $156 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s Generation & Marketing segment subsidiaries (while, as of that date, AEP’s Generation & Marketing segment subsidiaries posted approximately $153 million with counterparties and exchanges). Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP. Their ages are given as of February 13, 2025. The officers are appointed annually for a one-year term by the board of directors of AEP.

William J. Fehrman

President, Chief Executive Officer and Director

Age 64

President, Chief Executive Officer and Director since August 2024. President and Chief Executive Office of Centuri Holdings, Inc. from January 2024 to July 2024. President, Chief Executive Officer and Director of Berkshire Hathaway Energy Company from 2018 to 2023.

David M. Feinberg

Executive Vice President, General Counsel and Secretary

Age 55

Executive Vice President since January 2013. General Counsel and Secretary since January 2012.

Kelly J. Ferneau

Executive Vice President and Chief Nuclear Officer

Age 56

Executive Vice President and Chief Nuclear Officer since November 2024. I&M Site Vice President-Donald C. Cook Plant from July 2022 to October 2024. I&M Plant Manager from 2018 to June 2022.

Q. Shane Lies

Executive Vice President - Projects and Services

Age 54

Executive Vice President - Projects and Services since November 2024. Executive Vice President and Chief Nuclear Officer from September 2024 to November 2024. Senior Vice President and Chief Nuclear Officer from July 2022 to September 2024. I&M Site Vice President-Donald C. Cook Plant from January 2016 to July 2022.

Trevor I. Mihalik

Executive Vice President and Chief Financial Officer

Age 58

Executive Vice President and Chief Financial Officer since January 2025. Executive Vice President and Group President of Sempra from January 2024 to January 2025. Executive Vice President and Chief Financial Officer of Sempra from 2018 to 2023. Senior Vice President-Controller and Chief Accounting Officer of Sempra from 2012 to 2018.

Therace M. Risch

Executive Vice President and Chief Information & Technology Officer

Age 51

Executive Vice President since July 2021. Chief Information & Technology Officer since April 2020. Senior Vice President from April 2020 to July 2021. Executive Vice President, Chief Information Officer of JCPenney from December 2015 to April 2020.

Antonio P. Smyth

Executive Vice President - Grid Solutions

Age 48

Executive Vice President - Grid Solutions since December 2024. Executive Vice President - Grid Solutions & Government Affairs from April 2023 to December 2024. Senior Vice President - Grid Solutions from January 2021 to April 2023. Senior Vice President - Transmission Ventures, Strategy & Policy from October 2018 to December 2020.

Phillip R. Ulrich

Executive Vice President and Chief Human Resources Officer

Age 54

Executive Vice President since January 2023. Chief Human Resources Officer since August 2021. Senior Vice President from August 2021 to December 2022. Chief Human Resources Officer of Flex, LTD from May 2019 to July 2021.

GENERAL RISKS OF REGULATED OPERATIONS

AEP may not be able to recover the costs of substantial planned investment in capital improvements and additions. (Applies to all Registrants)

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

Regulated electric revenues and earnings are dependent on federal and state regulation that may limit AEP’s ability to recover costs and other amounts. (Applies to all Registrants)

The rates customers pay to AEP regulated utility businesses are subject to approval by the FERC and the respective state utility commissions of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. In certain instances, AEP’s applicable regulated utility businesses may agree to negotiated settlements related to various rate matters that are subject to regulatory approval. AEP cannot predict the ultimate outcomes of any settlements or the actions by the FERC or the respective state commissions in establishing rates.

If regulated utility earnings exceed the returns established by the relevant commissions, retail electric rates may be subject to review and possible reduction by the commissions, which may decrease future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, it could reduce future net income and cash flows and negatively impact financial condition. Similarly, if recovery or other rate relief authorized in the past is overturned or reversed on appeal, future earnings could be negatively impacted. Any legislation, regulatory action or litigation outcome that triggers a reversal of a regulatory asset or deferred cost generally results in an impairment to the balance sheet and a charge to the income statement of the company involved. New legislation could be adopted in any of the states in which we operate that could alter the regulatory framework and prevent us from getting timely recovery of our costs and investments.

In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the AEP regulated utility businesses and in base rates and examine, among other things, the reasonableness or prudence of operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions and previously incurred capital expenditures that the regulated utility businesses seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the regulated utility businesses to experience regulatory lag in recovering costs through rates, such that they may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, further exacerbating the regulatory lag and leading to additional uncertainty associated with rate case proceedings.

The AEP regulated utility businesses have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation and maintenance of their assets and infrastructure, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such events, or the quality of their service or the reasonableness of the cost of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the regulated utility businesses.

The regulated utility businesses, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation, tariffs, high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect AEP’s business, financial position, results of operation or cash flows. See Note 4 – Rate Matters for additional information.

AEP’s transmission investment strategy and execution are dependent on federal and state regulatory policy. (Applies to all Registrants)

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

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

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

Inquiries related to rates of return, as well as challenges to the formula rates of other utilities, are ongoing in other proceedings at the FERC. The results of these proceedings could potentially negatively impact AEP in any future challenges to AEP’s formula rates. If the FERC orders revenue reductions, including refunds, in any future cases related to its formula rates, it could reduce future net income and cash flows and impact financial condition.

End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to AEP, particularly if rates for delivered electricity increase substantially.

AEP faces risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project development agreements that may impede their development and operating activities. (Applies to all Registrants)

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

Changes in technology and regulatory policies may lower the value of electric utility facilities and franchises. (Applies to all Registrants)

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

AEP may not recover costs incurred to begin construction on projects that are canceled. (Applies to all Registrants)

AEP’s business plan for the construction of new projects, including providing service to new large load customers, involves a number of risks, including incomplete or inaccurate forecasting, planning and procurement, construction delays, non-performance by equipment and other third-party suppliers and increases in equipment and labor costs. To limit the risks of these construction projects, AEP’s subsidiaries enter into interconnection and service agreements, equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals, cost recovery and/or siting or environmental permits. If any of these projects are canceled for any reason, including shifts in large customer needs, preferences or financial stability, failure to receive necessary regulatory approvals, cost recovery and/or siting or environmental permits, significant unrecoverable costs or cancellation penalties under the equipment purchase orders and construction contracts could occur. In addition, if any construction work or investments have been recorded as an asset, an impairment may need to be recorded in the event the project is canceled.

AEP is exposed to nuclear generation risk. (Applies to AEP and I&M)

I&M owns the Cook Plant, which consists of two nuclear generating units for a rated capacity of 2,296 MWs, or about a tenth of the regulated generating capacity in the AEP System as of December 31, 2024. AEP and I&M are, therefore, subject to the risks of nuclear generation, which include the following:

• The potential harmful effects on the environment and human health due to an adverse incident/event resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as SNF.
• Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations.
• Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance unless the NRC specifies a lesser amount and potentially contribute to the coverage for losses of others).
• Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if these risks are triggered.

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

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities. Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs. The ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

AEP subsidiaries are exposed to risks through participation in the market and transmission structures in various regional power markets that are beyond their control. (Applies to all Registrants)

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

AEP could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to all Registrants)

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

A substantial portion of the receivables of AEP Texas is concentrated in a small number of REPs, and any delay or default in payment could adversely affect its cash flows, financial condition and results of operations. (Applies to AEP and AEP Texas)

AEP Texas collects receivables from the distribution of electricity from REPs that supply the electricity it distributes to its customers. As of December 31, 2024, AEP Texas did business with approximately 135 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for these services or could cause them to delay such payments. AEP Texas depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which AEP Texas can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and AEP Texas thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. In 2024, AEP Texas’ two largest REPs accounted for 40% of its operating revenue. Any delay or default in payment by REPs could adversely affect cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments AEP Texas had received from such REP.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

AEP’s financial performance may be adversely affected if AEP is unable to successfully operate facilities or perform certain corporate functions. (Applies to all Registrants)

Performance is highly dependent on the successful operation of generation, transmission and/or distribution facilities. Operating these facilities involves many risks, including:

• Operator error and breakdown or failure of equipment or processes.
• Operating limitations that may be imposed by environmental or other regulatory requirements.
• Labor disputes.
• Compliance with mandatory reliability standards, including mandatory cybersecurity standards.
• Information technology failure, including failure of artificial intelligence technology, that impairs AEP’s information technology infrastructure or disrupts normal business operations.
• Information technology failure that affects AEP’s ability to access customer information or causes loss of confidential or proprietary data that materially and adversely affects AEP’s reputation or exposes AEP to legal claims.
• Supply chain disruptions and inflation.
• Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by suppliers and other factors.
• Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornadoes, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.
• Fuel costs and related requirements triggered by financial stress in the coal industry.

Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation. (Applies to all Registrants)

AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack. The Federal government has notified the owners and operators of critical infrastructure, such as AEP, that the conflict between Russia and Ukraine has increased the likelihood of a cyber-attack on such systems. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be subject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring.

AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud and disruption of remote access across the AEP subsidiaries, there has been no material impact on business or operations from these attacks to date. Similarly, some of AEP’s third-party vendors have experienced cybersecurity incidents, though such incidents have not, to AEP’s knowledge, resulted in a material impact to AEP to date. However, AEP cannot guarantee that security efforts will detect or prevent future breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future. While AEP maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.

AEP is subject to standards enacted by the North American Electric Reliability Corporation and enforced by FERC regarding protection of critical infrastructure assets required for operating North America's bulk electric system. While AEP believes it is in compliance with such standards and regulations, AEP has been, and may in the future be, found to be in violation of such standards and regulations. To date, such violations have not resulted in material financial penalties; however, management can give no assurance that compliance efforts will not result in material penalties in the future. In addition, compliance with or changes in the applicable standards and regulations may subject AEP to higher operating costs and/or increased capital expenditures as well as substantial fines for non-compliance.

The failure of AEP or third-party vendor information technology systems, or the failure to enhance existing information technology systems and implement new technology, could adversely affect AEP. (Applies to all Registrants)

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

The amount of taxes imposed on AEP could change. (Applies to all Registrants)

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

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

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

Certain sources of insurance and debt and equity capital have expressed increasing unwillingness to procure insurance for or to invest in companies, such as AEP, that rely on fossil fuels. The public holds diverse and often conflicting views on the use of fossil fuels. AEP has multiple stakeholders, including our shareholders, customers, associates, federal and state regulatory authorities, and the communities in which AEP operates, and these stakeholders will often have differing priorities and expectations regarding issues related to the use of fossil fuels. Any adverse publicity in connection with AEP’s use of fossil fuels could curtail availability from certain sources of capital. If sources of capital for AEP are reduced and/or expected sale proceeds do not become available, capital costs could increase materially. Restricted access to capital or insurance markets and/or increased borrowing costs or insurance premiums could reduce future net income and cash flows and negatively impact financial condition. If AEP is not able to access debt or equity at competitive rates or at all, the ability to finance its operations and implement its strategy and business plan as scheduled could be adversely affected. An inability to access debt and equity may limit AEP’s ability to pursue improvements or acquisitions that it may otherwise rely on for future growth.

Our financial position may be adversely impacted if announced dispositions do not occur as planned. (Applies to AEP)

Any planned sale of assets and investments, including the announced transaction involving a noncontrolling interest in IMTCo and OHTCo, may not occur for any number of reasons beyond our control, including regulatory approval. If the transaction is unable to be completed, it could reduce future expected cash flows and impact financial condition.

Shareholder activism could cause AEP to incur significant expense, hinder execution of AEP’s business strategy and impact AEP’s stock price. (Applies to all Registrants)

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

Downgrades in AEP’s credit ratings could negatively affect its ability to access capital. (Applies to all Registrants)

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

AEP and AEPTCo have no income or cash flow apart from dividends paid or other payments due from their subsidiaries. (Applies to AEP and AEPTCo)

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

AEP’s operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. (Applies to all Registrants)

Electric power consumption is generally seasonal. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, overall operating results in the future may fluctuate substantially on a seasonal basis. In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce future net income and cash flows and negatively impact financial condition. In addition, unusually extreme weather conditions could impact AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions triggered by any cause, including tariffs, generally result in reduced consumption by customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues. The current administration has implemented tariffs on certain imported goods and may impose additional tariffs. As a result, prevailing economic conditions may reduce future net income and cash flows and negatively impact financial condition.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning. (Applies to all Registrants and to AEP and I&M with respect to the costs of nuclear decommissioning)

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy and the frequency and amount of AEP’s required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and AEP could be required from time to time to fund the pension plan with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations.

Additionally, I&M holds a significant amount of assets in its nuclear decommissioning trusts to satisfy obligations to decommission its nuclear plant. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.

Supply chain disruptions, tariffs and inflation could negatively impact our operations and corporate strategy. (Applies to all Registrants)

AEP’s operations and business plans depend on the global supply chain to procure the equipment, materials and other resources necessary to build and provide services in a safe and reliable manner. The delivery of components, materials, equipment and other resources that are critical to AEP’s business operations and corporate strategy has been restricted by domestic and global supply chain upheaval. This has resulted in the shortage of critical items. International tensions from any source, including the ramifications of regional conflict or increased tariffs, could further exacerbate the global supply chain upheaval. These disruptions and shortages could adversely impact business operations and corporate strategy. The current administration has implemented tariffs on certain imported goods and may impose additional tariffs. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that are needed to support normal operations or are required to execute on AEP’s corporate strategy for continued capital investment in utility equipment and impact AEP’s strategy to transition its generation fleet. These disruptions and constraints could reduce future net income and cash flows and possibly harm AEP’s financial condition.

The United States economy has been in an elevated inflationary environment and supply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions, including increased tariffs, could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to recover increased capital costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. Increases in inflation raises our costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact our financial condition.

AEP’s results of operations and cash flows may be negatively affected by a lack of growth or slower growth in the number of customers, a decline in customer demand or a recession. (Applies to all Registrants)

Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional power generation and delivery facilities. Customer growth and customer usage are affected by a number of factors outside the control of AEP, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity, including changes due to public health considerations.

Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to further reduce energy consumption. Additionally, technological advances or other improvements in or applications of technology could lead to declines in per capita energy consumption. Some or all of these factors, could impact the demand for electricity.

Failure to attract and retain an appropriately qualified workforce could harm results of operations. (Applies to all Registrants)

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include potential higher rates of existing employee departures, lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, operations may be negatively impacted and future net income and cash flows may be reduced.

Changes in the price of purchased power and commodities, the cost of procuring fuel, emission allowances for criteria pollutants and the costs of transport may increase AEP’s cost of purchasing and producing power, impacting financial performance. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

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 has existing contracts of varying durations for the supply of fuel, but as these contracts end or if they are not honored, AEP may not be able to purchase fuel on terms as favorable as the current contracts. AEP typically recovers increases in fuel expenses and purchased power from customers in regulated jurisdictions. Failure to recover these costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. 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, and while AEP typically recovers expenditures for undepreciated plant balances, there can be no assurance in the future that AEP will recover such costs. Similarly, AEP is exposed to changes in the price and availability of emission allowances. AEP uses emission allowances based on the amount of fuel used and reductions achieved through emission controls and other measures. Based on current environmental programs remaining in effect, AEP has sufficient emission allowances available through either EPA original issuance or market purchases to cover projected needs for the next two years and beyond. Additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions. If AEP needs to obtain allowances, those purchases may not be on as favorable terms as those under the current environmental programs. AEP’s risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

Prices for coal, natural gas and emission allowances have shown material swings in the past. Changes in the cost of purchased power, fuel or emission allowances and changes in the relationship between such costs and the market prices of power could reduce future net income and cash flows and negatively impact financial condition. In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value trading and marketing transactions, and those differences may be material. As a result, as those transactions are marked-to-market, they may impact future results of operations and cash flows and impact financial condition.

AEP is subject to physical and financial risks associated with climate change. (Applies to all Registrants)

Climate change creates physical and financial risk. Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events, such as fires. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require AEP to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the AEP service territory could also have an impact on revenues. AEP buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on AEP’s own and/or other systems may raise electricity prices as AEP buys short-term energy to serve AEP’s own system, which would increase the cost of energy AEP provides to customers.

Severe weather and weather-related events impact AEP’s service territories, primarily when thunderstorms, tornadoes, hurricanes, fires, floods and snow or ice storms occur. To the extent the frequency and intensity of extreme weather events and storms increase, AEP’s cost of providing service will increase, including the costs and the availability of procuring insurance related to such impacts, and these costs may not be recoverable. Changes in wind patterns or in precipitation resulting in droughts, water shortages or floods could adversely affect operations, principally wind generation facilities for changes in wind patterns and the fossil fuel generating units for changes in precipitation. A change in wind patterns or a negative impact to water supplies due to long-term drought conditions or severe flooding could adversely impact AEP’s ability to provide electricity to customers, as well as increase the price they pay for energy. AEP may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact revenues. AEP’s financial performance is tied to the health of the regional economies AEP serves. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of the communities within AEP’s service territories. Climate change may impact the economy, which could impact our sales and revenues. The cost of additional regulatory requirements, such as regulation of carbon dioxide emissions, could impact the availability of goods and prices charged by AEP’s suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and carbon dioxide emissions as a financial risk, this could negatively affect AEP’s ability to access capital markets or cause AEP to receive less than ideal terms and conditions in capital markets.

The occurrence of one or more wildfires could cause tremendous loss, impact the market value and credit ratings of our securities and have a material adverse effect on our financial condition. (Applies to all Registrants)

More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. AEP’s infrastructure could pose risks to safety and system reliability and wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related events. Wildfires can occur even when effective mitigation procedures are followed. Despite AEP’s early-stage wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which could subject AEP to significant liability. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, increased costs for insurance and mitigation efforts, regulatory recovery risk, litigation risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.

The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to AEP’s workforce and the general public. (Applies to all Registrants)

Electricity poses hazards for AEP’s workforce and the general public in the event that either comes in contact with electrical current or equipment, including through energized downed power lines or through equipment malfunctions. In addition, the risks associated with the operation of transmission and distribution assets and power generation and storage facilities include public and workforce safety issues and the risk of utility assets causing or contributing to wildfires. Deaths, injuries and property damage caused by such events can subject AEP to liability that, despite the existence of insurance coverage, can be significant. In addition, AEP may be held responsible for the actions of its contractors. No assurance can be given that future losses will not exceed the limits of AEP’s or its contractors’ insurance coverage.

Management cannot predict the outcome of the legal proceedings relating to AEP’s business activities. (Applies to all Registrants)

AEP is involved in legal proceedings, claims and litigation arising out of its business operations, the most significant of which are summarized in Note 6 - Commitments, Guarantees and Contingencies. Adverse outcomes in these proceedings could require significant expenditures that could reduce future net income and cash flows and negatively impact financial condition.

Disruptions at power generation facilities owned by third-parties could interrupt the sales of transmission and distribution services. (Applies to AEP and AEP Texas)

AEP Texas transmits and distributes electric power that the REPs obtain from power generation facilities owned by third-parties. If power generation is disrupted or if power generation capacity is inadequate, sales of transmission and distribution services may be diminished or interrupted, and results of operations, financial condition and cash flows could be adversely affected.

Management is unable to predict the course, results or impact, if any, of current or future litigation or investigations relating to the severe winter weather in Texas in February 2021. (Applies to AEP and AEP Texas)

As a result of the February 2021 severe winter weather in Texas which caused a shortage of electric generation, ERCOT instructed AEP Texas and other Texas electric utilities to initiate power outages to avoid a sustained large-scale outage and prevent long-term damage to the electric system. At its peak, approximately 468,000 (44%) AEP Texas customers were without power. In February 2021, AEP Texas received a Civil Investigative Demand from the Office of the Attorney General of Texas requesting, among other data, information about its communications to and from ERCOT, PUCT, retail electric providers, utilities, or power generation companies, concerning power outages related to the February 2021 winter storm. The company responded to the Civil Investigative Demand in March 2021.

AEP Parent and AEP Texas are named in approximately 100 lawsuits alleging multiple claims of wrongful death, personal injury, property damage and other injuries and damages. Certain wind farms formerly owned by AEP have also been named as defendants in up to approximately 125 lawsuits, along with other Texas energy companies and transmission and distribution utilities. Most of the lawsuits contain hundreds of plaintiffs and one of the suits is a purported class action on behalf of all customers in ERCOT. The complaints seek monetary damages among other forms of relief.

The litigation has been consolidated into a multi-district litigation (MDL) proceeding in Texas state court. The judge overseeing the MDL issued an initial case management order and stayed discovery. Two appeals regarding motions to dismiss the plaintiffs’ claims filed in representative cases by AEP Texas and other similarly situated defendants are currently pending; resolution of either of these appeals in favor of AEP Texas would result in dismissal of the plaintiffs’ claims against AEP Texas in those cases. A separate appeal regarding a motion to dismiss filed on behalf of the three formerly AEP-owned wind farms and other similarly situated defendants is also pending; resolution of this appeal in favor of the three wind farms would result in dismissal of the plaintiffs’ claims against the wind farms in those cases. Management is unable to predict the course or outcome of these or any future litigation or investigations or their impact, if any, on future results of operations, financial condition and cash flows.

Hazards associated with high-voltage electricity transmission may result in suspension of AEP’s operations or the imposition of civil or criminal penalties. (Applies to all Registrants)

AEP operations are subject to the usual hazards associated with high-voltage electricity transmission, including explosions, fires, inclement weather, natural disasters, mechanical failure, unscheduled downtime, equipment interruptions, remediation, chemical spills, discharges or releases of toxic or hazardous substances or gases and other environmental risks. The hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. AEP maintains property and casualty insurance, but AEP is not fully insured against all potential hazards incident to AEP’s business, such as damage to poles, towers and lines or losses caused by outages.

AEPTCo depends on AEP affiliates for a substantial portion of its revenues. (Applies to AEPTCo)

AEPTCo’s principal transmission service customers are AEP affiliates. Management expects that these affiliates will continue to be AEPTCo’s principal transmission service customers for the foreseeable future. For the year ended December 31, 2024, AEP affiliates were responsible for approximately 80% of the consolidated transmission revenues of AEPTCo.

Most of the real property rights on which the assets of AEPTCo are situated result from affiliate license agreements and are dependent on the terms of the underlying easements and other rights of its affiliates. (Applies to AEPTCo)

AEPTCo does not hold title to the majority of real property on which its electric transmission assets are located. Instead, under the provisions of certain affiliate contracts, it is permitted to occupy and maintain its facilities upon real property held by the respective AEP subsidiary utility affiliate that overlay its operations. The ability of AEPTCo to continue to occupy such real property is dependent upon the terms of such affiliate contracts and upon the underlying real property rights of these utility affiliates, which may be encumbered by easements, mineral rights and other similar encumbrances that may affect the use of such real property. AEP can give no assurance that (a) the relevant AEP subsidiary utility affiliates will continue to be affiliates of AEPTCo, (b) suitable replacement arrangements can be obtained in the event that the relevant AEP subsidiary utility affiliates are not its affiliates and (c) the underlying easements and other rights are sufficient to permit AEPTCo to operate its assets in a manner free from interruption.

Compliance with legislative and regulatory requirements may lead to increased costs and result in penalties. (Applies to all Registrants)

Business activities of electric utilities and related companies are heavily regulated, primarily through national and state laws and regulations of general applicability, including laws and regulations related to working conditions, health and safety, equal employment opportunity, employee benefit and other labor and employment matters, laws and regulations related to competition and antitrust matters. Many agencies employ mandatory civil penalty structures for regulatory violations. Registrants are subject to the jurisdiction of many federal and state agencies, including the FERC, NERC, Commodities Futures Trading Commission, Federal EPA, NRC, Occupational Safety and Health Administration, the SEC and the United States Department of Justice which may impose significant civil and criminal penalties to enforce compliance requirements relative to AEP’s business, which could have a material adverse effect on financial operating results including earnings, cash flow and liquidity.

The impact of new laws, regulations and policies and the related interpretations, as well as changes in enforcement practices or regulatory scrutiny generally cannot be predicted, and changes in applicable laws, regulations and policies and the related interpretations and enforcement practices may require extensive system and operational changes, be difficult to implement, increase AEP’s operating costs, require significant capital expenditures, or adversely impact the cost or attractiveness of the products or services AEP offers, or result in adverse publicity and harm AEP’s reputation.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Costs of compliance with existing and evolving environmental laws are significant. (Applies to all Registrants except AEPTCo)

Operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. A majority of the electricity generated by AEP subsidiaries is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals or CCR) resulting from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements (including any new and more stringent application of existing CCR regulations) requires AEP to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits at AEP facilities and could cause AEP to retire generating capacity prior to the end of its estimated useful life. Costs of compliance with environmental statutes and regulations could reduce future net income and negatively impact financial condition, especially if emission limits, CCR waste discharge and/or discharge disposal obligations are tightened, more extensive operating and/or permitting requirements are imposed or additional substances or facilities become regulated. Although AEP typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance in the future that AEP will recover the remaining costs associated with such plants. Failure to recover these costs could reduce future net income and cash flows and possibly harm financial condition.

Regulation of greenhouse gas emissions could materially increase costs to AEP and its customers or cause some electric generating units to be uneconomical to operate or maintain. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

Federal or state laws or regulations may be adopted that would impose new or additional limits on the emissions of greenhouse gases, including, but not limited to, carbon dioxide and methane, from electric generation units using fossil fuels like coal. The potential effects of greenhouse gas emission limits on AEP's electric generation units are subject to significant uncertainties based on, among other things, the timing of the implementation of any new requirements, the required levels of emission reductions, the nature of any market-based or tax-based mechanisms adopted to facilitate reductions, the relative availability of greenhouse gas emission reduction offsets, the development of cost-effective, commercial-scale carbon capture and storage technology and supporting regulations and liability mitigation measures, and the range of available compliance alternatives.

AEP is committed to providing reliable affordable power to its customers. To achieve this, AEP and its subsidiaries routinely meet with state regulators and key stakeholders to understand their needs for both dispatchable and renewable generation resources. This process evaluates, amongst other things, future supply and demand fundamentals, the economic aspects of investments, grid reliability and resilience, regulations and evolving RTO requirements, the advancement of generation technologies, and market impacts and constraints. As part of the regulatory process, AEP routinely submits IRPs in various regulatory jurisdictions to address future generation needs. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. AEP remains committed to making generation and capacity resource decisions that provide the most cost-efficient and reliable power to customers, irrespective of any specific carbon-reduction goal. Based on the assumptions used in the most recent analysis, AEP expects that its Scope 1 GHG emissions will be reduced by 80% by 2030 (from a 2005 baseline).

AEP’s GHG reduction efforts are predicated on the combined preferences of the eleven states that we operate in. AEP has made significant progress in reducing GHG emissions from its power generation fleet and while we aspire to be at net-zero Scope 1 and 2 emissions by 2045, our performance will ultimately be driven by the needs and desires of the states we serve. AEP is engaging with regulators and policymakers and our decisions around generation resources are reflected in the preferences of these states. AEP has embraced the advancement of low-carbon generation solutions where supported, which may include early-stage projects to bring small modular nuclear reactors to Virginia and Indiana as an example. Further advancement of affordable new generation technologies and a market for offsets, as well as continued alignment with our states, would be required to achieve net-zero emissions.

AEP’s results of operations could be materially adversely affected to the extent that new federal or state laws or regulations impose any new greenhouse gas emission limits. Any future limits on greenhouse gas emissions could create substantial additional costs in the form of taxes or emissions allowances, require significant capital investment in carbon capture and storage technology, fuel switching, or the replacement of high-emitting generation facilities with lower-emitting generation facilities and/or could cause AEP to retire generating capacity prior to the end of its estimated useful life. Although AEP typically recovers environmental expenditures, there can be no assurance in the future that AEP can recover such costs which could reduce future net income and cash flows and possibly harm financial condition. Further, real or alleged violations of environmental regulations, including those related to climate change, or an inability to meet AEP’s voluntary climate aspirations, could adversely impact AEP’s reputation, reduce future net income and cash flows and harm financial condition.

AEP may be unable to procure or construct generation capacity when needed or to recover the costs of such generation capacity. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP’s capacity obligations are subject to a number of factors including load growth, requirements that can be imposed by the states, RTOs and other jurisdictions in which it operates or participates as a member and the retirement of existing generating facilities. AEP must obtain new and replacement generation to comply with prevailing capacity needs and reserve obligations. AEP’s ability to acquire, retrofit and/or construct power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for capital, materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, continued pandemic-related delays and cost increases, and supply chains and material constraints, including those that may result from major storm events. Delays in obtaining permits, challenges in securing suitable land for the siting, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, supply chain delays or disruptions, and other events beyond AEP’s control may occur that may materially affect the schedule, cost, and performance of needed acquisitions or construction projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, AEP could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, AEP could be exposed to higher costs, penalties and market volatility, which could affect cash flow and cost recovery, should one or more applicable regulator decline to approve the acquisition or construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

Courts adjudicating nuisance and other similar claims in the future may order AEP to pay damages or to limit or reduce emissions. (Applies to all Registrants except AEP Texas and AEPTCo)

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which AEP, among others, were defendants. In general, the actions allege that emissions from the defendants’ power plants constitute a public nuisance. The plaintiffs in these actions generally seek recovery of damages and other relief. If future actions are resolved against AEP, substantial modifications or retirement of AEP’s existing coal-fired power plants could be required, and AEP might be required to purchase power from third-parties to fulfill AEP’s commitments to supply power to AEP customers. This could have a material impact on revenues. In addition, AEP could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. Unless recovered, those costs could reduce future net income and cash flows and harm financial condition. Moreover, results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)

AEP routinely has open trading positions in the market, within guidelines set by AEP, resulting from the management of AEP’s trading portfolio. To the extent open trading positions exist, fluctuating commodity prices can improve or diminish financial results and financial position. AEP’s power trading activities also expose AEP to risks of commodity price movements. To the extent that AEP’s power trading does not hedge the price risk associated with the generation it owns, or controls, AEP would be exposed to the risk of rising and falling spot market prices. In connection with these trading activities, AEP routinely enters into financial contracts, including futures and options, OTC options, financially-settled swaps and other derivative contracts. These activities expose AEP to risks from price movements. If the values of the financial contracts change in a manner AEP does not anticipate, it could harm financial position or reduce the financial contribution of trading operations.

Parties with whom AEP has contracts may fail to perform their obligations, which could harm AEP’s results of operations. (Applies to all Registrants)

AEP sells power from its generation facilities into the spot market and other competitive power markets on a contractual basis. AEP also enters into contracts to purchase and sell electricity, natural gas, emission allowances, renewable energy credits and coal as part of its power marketing and energy trading operations. AEP is exposed to the risk that counterparties that owe AEP money or the delivery of a commodity, including power, could breach their obligations. Should the counterparties to these arrangements fail to perform, AEP may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed AEP’s contractual prices, which would cause financial results to be diminished and AEP might incur losses. Although estimates take into account the expected probability of default by a counterparty, actual exposure to a default by a counterparty may be greater than the estimates predict.

AEP relies on electric transmission facilities that AEP does not own or control. If these facilities do not provide AEP with adequate transmission capacity, AEP may not be able to deliver wholesale electric power to the purchasers of AEP’s power. (Applies to all Registrants)

AEP depends on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power AEP sells at wholesale. This dependence exposes AEP to a variety of risks. If transmission is disrupted, or transmission capacity is inadequate, AEP may not be able to sell and deliver AEP wholesale power. If a region’s power transmission infrastructure is inadequate, AEP’s recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Management also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

OVEC may require additional liquidity and other capital support. (Applies to AEP, APCo, I&M and OPCo)

AEP and several nonaffiliated utility companies own OVEC. The Inter-Company Power Agreement (ICPA) defines the rights and obligations and sets the power participation ratio of the parties to it. Under the ICPA, parties are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,400 MWs) in proportion to their respective power participation ratios. The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%. If a party fails to make payments owed by it under the ICPA, OVEC may not have sufficient funds to honor its payment obligations, including its ongoing operating expenses as well as its indebtedness. As of December 31, 2024, OVEC has outstanding indebtedness of approximately $997 million, of which APCo, I&M and OPCo are collectively responsible for $433 million through the ICPA. Although they are not an obligor or guarantor, APCo, I&M and OPCo are responsible for their respective ratio of OVEC’s outstanding debt through the ICPA and if OVEC’s indebtedness is accelerated for any reason, there is risk that APCo, I&M and/or OPCo may be required to pay some or all of such accelerated indebtedness in amounts equal to their aggregate power participation ratio of 43.47%.

New climate disclosure rules proposed by the U.S. Securities and Exchange Commission may increase our costs of compliance and adversely impact our business. (Applies to all Registrants)

On March 24, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related risks. The rules have been challenged in court and are currently stayed. At this time AEP cannot predict the costs of implementation or any potential adverse impacts resulting from the rule as adopted. To the extent these rules or any replacement rules are adopted, AEP could incur increased costs relating to the assessment and disclosure of climate-related risks. AEP may also face increased litigation risks related to disclosures made pursuant to any rules that are implemented. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.

The electric utility industry is an identified critical infrastructure function with mandatory cybersecurity requirements under the authority of FERC. The NERC, which FERC certified as the nation’s Electric Reliability Organization, developed mandatory critical infrastructure protection cybersecurity reliability standards. AEP’s service territory covers multiple NERC regions and is audited at least annually by one or more of the regions. AEP has participated in the NERC grid security and emergency response exercises, GridEx, for the past ten years and continues to participate in the bi-yearly exercises. These NERC-led efforts test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid. AEP also conducts internal exercises to test and further refine AEP’s cyber response plans. These internal scenarios are chosen based on real world events and often include coordination with and communication to AEP’s Chief Executive Officer and executive team.

The operations of AEP’s electric utility subsidiaries are subject to extensive and rigorous mandatory cyber and physical security requirements that are developed and enforced by NERC to protect grid security and reliability. Cook Plant is also subject to NRC regulation for cybersecurity. AEP’s enterprise-wide security program includes cyber and physical security and incorporates many of the guidelines set forth in the National Institute of Standards and Technology Cybersecurity Framework. AEP'’s Chief Security Officer (CSO) has accountability for cyber aspects of third-party risk and data loss prevention and is also its NERC Critical Infrastructure Protection Senior Manager, who is responsible for ensuring alignment of compliance with the enterprise-wide security program. AEP’s CSO possesses extensive experience across cybersecurity, risk and data controls and infrastructure engineering. AEP’s CSO was the Chief Security Officer at Bread Financial Holdings, Inc., a publicly registered financial services company, and an executive director of cyber security at JPMorgan Chase & Co. prior to joining AEP.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cybersecurity controls and authentication. Cyber hackers and other malicious actors have caused material disruption by successfully breaching a number of very secure facilities of entities across the spectrum of industries, including federal agencies and financial institutions. As understanding of these events develop, AEP has adopted a defense in depth approach to cybersecurity and continually assesses its cybersecurity tools and processes to determine where to strengthen its defenses. These strategies include monitoring, alerting and emergency response, forensic analysis, disaster recovery, threat sharing and criminal activity reporting. This approach has allowed AEP to deal with cyber and related threats, intrusions and attempted breaches in real-time and to limit their impact to levels that would be expected in the ordinary course of business in the absence of such malicious activity. AEP is not aware of any occurrence from cybersecurity threats, including as a result of any previous cybersecurity incidents, that has materially affected or is reasonably likely to materially affect AEP’s business strategy, results of operations, cash flows or financial condition.

AEP has undertaken a variety of actions to monitor and address cyber-related risks. Cybersecurity and the effectiveness of AEP’s cybersecurity processes are reviewed annually with the Board of Directors and at several meetings throughout the year with the Technology Committee of the Board, the principal committee that exercises oversight with respect to these matters. AEP’s Chief Executive Officer and executive team participate in interactive threat briefings from AEP’s CSO and/or Chief Information & Technology Officer on a regular basis. AEP’s strategy and procedure for managing cyber-related risks is integrated within its enterprise risk management processes. These procedures are designed to ensure that any material information regarding potentially relevant cyber incidents is elevated in a timely manner both to the appropriate leadership and, where applicable, to our external financial reporting and disclosure team. AEP’s enterprise-wide security program continually adjusts staff and resources in response to the evolving threat landscape. The costs for such investments are material and have remained generally consistent over time, a pattern that is expected to continue. In addition, AEP maintains cyber liability insurance to cover certain damages caused by cyber incidents.

AEP’s CSO leads the cybersecurity and physical security teams which are responsible for the design, implementation and execution of AEP’s security risk management strategy, which includes cybersecurity. AEP’s cybersecurity team operates a 24/7 Cybersecurity Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. The cybersecurity team constantly scans the AEP System for cyber risks and threats. In addition, under the direction of the CSO, the cybersecurity team actively monitors best practices, performs penetration testing, leads response exercises and internal awareness campaigns and provides training and communication across the organization. AEP’s security awareness training is mandatory for all employees and includes regular phish email testing to train employees to identify malicious emails that could put AEP at risk.

AEP also continually reviews its business continuity plan to develop an effective recovery strategy that seeks to decrease response times, limit financial impacts and maintain customer confidence during any business interruption. AEP administers a third-party risk governance program that identifies potential risks introduced through third-party relationships, such as vendors, software and hardware manufacturers or professional service providers. As warranted, AEP obtains certain contractual security guarantees and assurances with these third-party relationships to help ensure the security and safety of its information. The cyber security team works closely with a broad range of departments, including legal, regulatory, corporate communications, internal audit services, information technology and operational technology functions critical to the power grid.

The cybersecurity team collaborates with partners from both industry and government, and routinely participates in industry-wide programs that exchange knowledge of threats with utility peers, industry and federal agencies. AEP is an active member of a number of industry-specific threat and information sharing communities including the Department of Homeland Security’s Joint Cyber Defense Collaborative, the Electricity Information Sharing and Analysis Center and the National Defense Information Sharing and Analysis Center. AEP participates in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. AEP continues to work with nonaffiliated entities to do penetration testing and to design and implement appropriate remediation strategies. There can be no assurance, however, that these efforts will be effective to prevent material interruption of services or other damages to AEP's business or operations in connection with any cyber-related incident. See “Risk Factors - Risks Related to Market, Economic or Financial Volatility and Other Risks - Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidential information and damage AEP’s reputation”.

GENERATION FACILITIES

The tables below summarize the net maximum capacity of AEP's owned generation plants as of December 31, 2024. AEP subsidiaries serve customer electricity needs from these facilities and from purchased power in the PJM and SPP markets based on demand and other economic conditions. AEP's regulated subsidiaries have approved recovery mechanisms in retail jurisdictions that recover the cost of prudently incurred fuel, purchased power and other expenses.

Vertically Integrated Utilities Segment

(a) AEGCo owns a 50% interest in the Rockport Plant units. I&M owns the remaining 50%. Figures presented reflect only the portion owned by AEGCo.

(a) I&M owns a 50% interest in the Rockport Plant units. AEGCo owns the remaining 50%. Figures presented reflect only the portion owned by I&M.

NA Not applicable.

(a) KPCo owns a 50% interest in the Mitchell Plant units. WPCo owns the remaining 50%. Figures presented reflect only the portion owned by KPCo.

(a) PSO owns a 45.5% interest and SWEPCo owns the remaining 54.5% interest in Sundance, Maverick and Traverse. Figures presented reflect only the portion owned by PSO.

NA Not applicable.

(a) Jointly-owned with nonaffiliated entities. Figures presented reflect only the portion owned by SWEPCo. The Arkansas jurisdictional portion of SWEPCo’s interest in Turk Plant is not in rate base.

(b) In November 2020, management announced it will cease using coal at the Welsh Plant in 2028. In December 2024, SWEPCo filed an application for a Certificate of Convenience and Necessity (CCN) with the APSC, LPSC and PUCT to convert Welsh Plant, Units 1 and 3 to natural gas in 2028 and 2027, respectively.

(c) SWEPCo owns a 54.5% interest and PSO owns the remaining 45.5% interest in Sundance, Maverick and Traverse. Figures presented reflect only the portion owned by SWEPCo.

NA Not applicable.

(a) WPCo owns 50% in the Mitchell Plant units. KPCo owns the remaining 50%. Figures presented reflect only the portion owned by WPCo.

TRANSMISSION AND DISTRIBUTION FACILITIES

The AEP System has significant investments in transmission and distribution lines across its Vertically Integrated Utilities, Transmission and Distribution Utilities and AEP Transmission Holdco Segments.

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple. The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority. The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business. Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties. AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines. AEP has experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which AEP’s operating companies have sought to acquire rights-of-way through condemnation. These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, AEP subsidiaries continuously assess the adequacy of their transmission, distribution, generation and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate. AEP forecasts approximately $11.5 billion of construction expenditures for 2025. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, supply chain issues, weather, legal reviews, inflation and the ability to access capital. See the “Budgeted Capital Expenditures” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to AEP’s generation plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and subsidiaries. For risks related to owning a nuclear generating unit, see the “Nuclear Contingencies” section of Note 6 - Commitments, Guarantees and Contingencies for additional information.

For a discussion of material legal proceedings, see Note 6 - Commitments, Guarantees and Contingencies for additional information.

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations. Year-to-year comparisons between 2023 and 2022 have been omitted from this Form 10-K but may be found in "Management's Discussion and Analysis of Financial Condition" in Part II, Item 7 of our Form 10-K for the fiscal year ended December 31, 2023, which specific discussion is incorporated herein by reference.

AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations.

AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under the “Quantitative and Qualitative Disclosures About Market Risk” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Disclosure Controls and Procedures

During 2024, management, including the principal executive officer and principal financial officer of each of the Registrants evaluated each respective Registrant’s disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2024, the principal executive officer and financial officer of each of the Registrants concluded that the disclosure controls and procedures in place were effective at the reasonable assurance level. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

Changes in Internal Control over Financial Reporting

There have been no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2024 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Internal Control over Financial Reporting

See Management’s Report on Internal Control over Financial Reporting for each Registrant under Item 8. As discussed in that report, management assessed and reported on the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2024. As a result of that assessment, management concluded that each Registrant’s internal control over financial reporting was effective as of December 31, 2024.