Item 1. BUSINESS

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, 2023, the subsidiaries of AEP had a total of 17,250 employees. Because it is a holding company rather than an operating company, AEP has no employees.

Information related to AEP subsidiary operating companies as of December 31, 2023 is shown in the table below:

						AEP Texas						AEPTCo						APCo						I&M						KGPCo (a)						KPCo						OPCo (b)						PSO						SWEPCo						WPCo
State of Incorporation						Delaware, 1925						Delaware, 2006						Virginia, 1926						Indiana, 1907						Virginia, 1917						Kentucky, 1919						Ohio, 1907						Oklahoma, 1913						Delaware, 1912						West Virginia, 1883
AEP Reportable Segment						Transmission and Distribution Utilities						AEP Transmission Holdco						Vertically Integrated Utilities						Vertically Integrated Utilities						Vertically Integrated Utilities						Vertically Integrated Utilities						Transmission and Distribution Utilities						Vertically Integrated Utilities						Vertically Integrated Utilities						Vertically Integrated Utilities
RTO Affiliation						ERCOT						(c)						PJM						PJM						PJM						PJM						PJM						SPP						SPP						PJM
Approximate Number of Retail Customers						1,111,000						(c)						967,000						613,000						49,000						163,000						1,527,000						578,000						548,000						41,000
Number of Employees						1,646						(c)						1,679						2,110						56						284						1,752						1,062						1,344						230
Overhead Circuit Miles of Transmission and Distribution Lines						46,673						4,188						51,558						20,584						1,405						11,210						44,519						18,156						26,233						1,722

(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, 2023, AEPSC had 6,736 employees.

Principal Industries Served

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

						AEP Texas						APCo						I&M						KGPCo						KPCo						OPCo						PSO						SWEPCo						WPCo
Principal Industries Served:
Petroleum and Coal Products Manufacturing						X																								X						X						X						X
Chemical Manufacturing						X						X						X						X						X						X												X						X
Oil and Gas Extraction						X																								X												X						X
Pipeline Transportation						X						X																		X						X						X												X
Primary Metal Manufacturing						X						X						X																		X												X						X
Data Processing (a)						X																														X
Coal-Mining												X																		X																								X
Paper Manufacturing												X												X																		X						X
Transportation Equipment																		X																																				X
Plastics and Rubber Products																		X						X												X						X
Fabricated Metals Product Manufacturing																		X
Food Manufacturing																																																X
Supply and Market Electric Power at Wholesale to:
Other Electric Utility Companies												X						X												X												X						X						X
Rural Electric Cooperatives												X						X																														X
Municipalities												X						X												X												X						X
Other Market Participants												X						X												X												X						X						X

(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:

Principal Jurisdiction						AEP Utility Subsidiaries Operating in that Jurisdiction						Authorized Return on Equity (a)
Arkansas						SWEPCo						9.50		%
FERC						AEPTCo - PJM						10.35		%	(b)
						AEPTCo - SPP						10.50		%
Indiana						I&M						9.70		%
Kentucky						KPCo						9.75		%	(c)
Louisiana						SWEPCo						9.50		%
Michigan						I&M						9.86		%
Ohio						OPCo						9.70		%
Oklahoma						PSO						9.30		%
Tennessee						KGPCo						9.50		%
Texas						AEP Texas						9.40		%
						SWEPCo						9.25		%	(d)
Virginia						APCo						9.50		%
West Virginia						APCo						9.75		%
						WPCo						9.75		%

(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)The KPSC issued an order approving a 9.75% ROE, effective January 2024. See “2023 Kentucky Base Rate and Securitization Case” section of Note 4 for additional information.

(d)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 19 - 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 debt. 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. See “Financial Condition” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2023 Annual Report 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/capital 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 $50 million, would cause an event of default under the credit agreements. As of December 31, 2023, 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 included in the 2023 Annual Report 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. 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 included in the 2023 Annual Report.

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 greenhouse gas emissions from fossil generation under Section 111 of the CAA.

Clean Water Act Requirements

The Federal EPA’s ELG rule for generation facilities establishes limits for FGD wastewater, fly ash and bottom ash transport water and flue gas mercury control wastewater, which are implemented through each facility’s wastewater discharge permit. In March 2023, the Federal EPA proposed further revisions to the ELG rule which, if finalized, would establish a zero discharge standard for FGD wastewater and bottom ash transport water, and more stringent discharge limits for combustion residual leachate. Management cannot predict whether the Federal EPA will actually finalize further revisions but will continue to monitor this issue and its potential impact to operations.

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. The rule applies to active and inactive CCR landfills and surface impoundments at facilities of active electric utility or independent power producers. In May 2023, the Federal EPA proposed 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 proposing 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 proposal establishes accelerated compliance deadlines for legacy surface impoundments to meet regulatory requirements, including a requirement to initiate closure within one year after the effective date of the final rule. The Federal EPA's proposal would require evaluations to be completed at both active facilities and inactive facilities with one or more legacy surface impoundments. If finalized, AEP may incur material, additional costs complying with the Federal EPA’s proposal, including costs to upgrade or close and replace legacy CCR surface impoundments and to conduct any required remedial actions including removal of coal ash. In addition, AEP would need to seek cost recovery through regulated rates, including proposing new regulatory mechanisms for cost recovery, for which regulatory approval cannot be assured. The proposed rule, if finalized, could have a material adverse impact on net income, cash flows and financial condition if AEP cannot ultimately recover any additional costs of compliance.

Climate Change, CO****2 Regulation and Energy Policy

To date, the Federal EPA has twice taken action to regulate CO2 emissions from new and existing fossil fueled electric generating units under the existing provisions of the CAA and both attempts have been struck down by the courts. In May 2023, the Federal EPA proposed greenhouse gas standards and guidelines for new and existing fossil-fuel fired sources. The proposal relies heavily on carbon capture and sequestration and natural gas co-firing as means to reduce CO2 emissions from coal fired plants and hydrogen co-firing and carbon capture and sequestration to reduce CO2 emissions from gas turbines. Management is evaluating the proposed rule.

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 included in the 2023 Annual Report for additional information.

Electric Industry Transformation

The electric utility industry is in the midst of an historic transformation, driven by changing customer needs, evolving public policies, stakeholder demands, demographics, competitive offerings, technologies and commodity prices. AEP is also transforming to be more agile and customer-focused as a valued provider of energy solutions. AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the results of the IRPs, management expects emissions to continue to decline over time as AEP diversifies generating sources and operates fewer coal units. The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.

As of December 31, 2023, AEP’s generating capacity included owned and PPA capacity of approximately 23,300 MWs and 5,200 MWs, respectively. In 2023, owned and PPA coal capacity represented 42% of AEP’s generating capacity compared with 70% in 2005.

The graph below summarizes AEP’s generating capacity by resource type for the years 1999, 2005 and 2023:

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

In addition, certain states AEP subsidiaries serve have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy or renewable energy sources. Management actively monitors AEP’s compliance position and is on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

As of December 31, 2023, AEP’s regulated utilities had long-term contracts for 2,750 MWs of wind, 80 MWs of hydro and 65 MWs of solar power. Additionally, as of December 31, 2023, AEP’s regulated utilities own and operate 1,639 MWs of wind, 816 MWs of hydro and 41 MWs of solar power.

End Use Energy Efficiency

Beginning in 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs. These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available. Since that time, AEP operating company programs have reduced annual consumption by over 10.5 million MWhs and peak demand by approximately 3,600 MWs. Management estimates that its operating companies spent approximately $1.7 billion since 2008 to achieve these levels.

Energy efficiency and demand reduction programs have received regulatory support in most of the states AEP serves, and appropriate cost recovery will be essential for AEP operating companies to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues, and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments. As AEP continues to transition to a cleaner, more efficient energy future, energy efficiency and demand response programs will continue to play an important role in how the company serves its customers.

Management believes its experience providing robust energy efficiency programs in several states positions AEP to be a cost-effective provider of these programs as states develop their implementation plans.

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. In 2023, AEP also established a Climate Change Executive Group to ensure appropriate management and accountability concerning climate-related impacts, risks and opportunities.

AEP routinely submits IRPs in various regulatory jurisdictions to address future generation and capacity needs. These IRPs take into account economics, customer demand, grid reliability and resilience, regulations and RTO capacity requirements. The objective of the IRPs is to recommend future generation and capacity resources that provide the most cost-efficient and reliable power to customers. Based on the output of the company’s IRPs, in October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals. AEP adjusted its near-term CO2 emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045 for Scope 1 and Scope 2 emissions. AEP’s total Scope 1 GHG estimated emissions in 2023 were approximately 42.8 million metric tons, a 68% reduction according to the GHG Protocol, which excludes emission reductions that result from assets that have been sold, or a 72% reduction from AEP’s 2005 Scope 1 GHG emissions (inclusive of emission reductions that result from plants that have been sold).

AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline over the long-term. AEP also expects Scope 1 GHG emissions to vary annually depending on the mix of its own generation and purchased power used to serve customers. AEP’s ability to achieve these goals is dependent upon a number of factors including the ability to execute on renewable resource plans, evolving RTO requirements, constructive regulatory support, the advancement of carbon-free generation technologies, customer demand for carbon-free energy, potential tariffs, carbon policy and regulation, operational performance of renewable generation and supply chain costs and constraints, all while continuing to provide the most cost-efficient and reliable power to customers.

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, 2023:

Subsidiary						Number of Employees
AEPSC						6,736
AEP Texas						1,646
APCo						1,679
I&M						2,110
OPCo						1,752
PSO						1,062
SWEPCo						1,344
Other						921
Total AEP						17,250

Of AEP’s 17,250 employees, less than 0.1% are Traditionalists (born before 1946), approximately 17% are Baby Boomers (born 1946-1964), approximately 36% are Generation X (born 1965-1980), approximately 39% are Millennials (born 1981-1996) and approximately 7% are Generation Z (born after 1996).

Safety

Safety is deeply embedded in our culture and is one of AEP’s core values because we care that everyone goes home at the end of each work day. We have policies, procedures, programs, training and proactive initiatives in place to help ensure a safe mindset and work environment. Unfortunately, in 2023, we suffered three devastating losses as two employees and one contractor lost their lives. The loss of a single life is unacceptable and we are determined to learn from each event, independently, so we can take action to better protect our employees and all those who support us. These events reinforce the importance of our endless commitment to a strong safety culture and the work it takes to operate safely. We are committed to taking bold steps 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 significant incidents, providing appropriate training and education and improving proactive safety initiatives and data analysis to identify and address potential performance gaps. One common industry safety metric utilized by AEP to track incidents is the Days Away/Restricted or Transferred (DART) rate. 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. In 2023, AEP’s employee DART rate performance improved to 0.384 as compared to 0.424 in 2022.

Culture and Inclusion

Culture serves as the foundation for success at AEP. An engaged, collaborative, inclusive and appreciated workforce is an empowered workforce – one that is more likely to embrace change, drive continuous improvement, take ownership, and value personal and professional growth. AEP views a culture of inclusion as a core business value that creates understanding, sparks innovation and allows us to better serve our customers. We are committed to building a work culture that champions respect and belonging, that leverages our differences as a strength. Inclusion is important to ensuring that AEP has the best talent to move our company forward and achieve business objectives. Our inclusion efforts are guided by four principles:

• Establishing leadership accountability around culture and inclusion outcomes.

• Building and maintaining a workforce that generally reflects the communities we serve.

• Promoting an inclusive culture where all employees can thrive.

• Supporting the communities we serve so they will prosper.

We believe our workforce generally should reflect the diversity of our customers and the communities we serve so that we may better understand how to tailor our services to meet their expectations. As of December 31, 2023, women comprised approximately 20% of AEP’s total workforce. As of December 31, 2023, approximately 21% of AEP’s total workforce was represented by racially or ethnically diverse employees.

Our progress is tied to enterprise, business unit and operating company annual incentive compensation objectives, which is measured through our annual employee culture survey. 2023 marks our tenth consecutive year of formally surveying employees about their experiences with culture at AEP. In 2023, 94% of our organization participated in the survey, and we continued to improve our performance remaining in the top decile compared to Gallup’s overall company database. The culture survey provides a process for leaders to share results with their teams, facilitate discussions to improve employee engagement and take actions toward that improvement throughout the year. AEP’s Human Resources Committee of the Board reviews the culture and employee engagement results annually, providing additional oversight. In addition, the Human Resources Committee of the Board provides oversight of our compensation and human resources policies and practices, including an annual review of our culture and inclusion strategy, and compliance with equal opportunity laws. In 2023, AEP received the Gallup Exceptional Workplace Award for the fourth consecutive year. This award recognizes organizations with engaged workplace cultures.

To support a culture of inclusion, AEP launched the Culture and Inclusion Council, which consists of decision makers from across the company to help lead our culture strategy. A key focus for the council will be prioritizing our Culture & Inclusion guiding principles. In addition, AEP launched the Access to Opportunity standards to enhance female and minority representation within AEP’s leadership and conducted pay equity studies to identify and address pay variances for female and minority employees. We are also signatories of the CEO Action for Diversity and Inclusion pledge, Paradigm for Parity and several other local and industry initiatives to demonstrate our commitment to advancing a culture of inclusion within the workplace.

In addition, we’re committed to working with the communities we serve to advance equity for our employees, customers and neighbors of color. The American Electric Power Foundation created the Delivering on the Dream grant program. This five-year, $5 million initial investment supports nonprofit organizations that are working to dismantle systemic racism and injustices in our communities.

Employee Resource Groups

One of the best ways for AEP to demonstrate our commitment to a trusting and inclusive work environment is to empower employees to form and participate in Employee Resource Groups (ERG). The ERGs at AEP include Abled and Differently-Abled Partnering Together, the Black ERG, the Asian-American Employee Partnership ERG, the Hispanic Origin Latin American ERG, the Military Veteran ERG, the Native American Tribes Interacting, Observing and Networking ERG, the Pride Partnership, the Women at Work ERG and the Empowered Parents and Caregivers ERG. Encouraging engagement through one of our nine ERGs creates meaningful connections through shared experiences and learning about different cultures and lived experiences for deeper understanding and knowledge. Their strategic priorities include recruiting and retaining diverse employees, identifying and participating in community volunteerism opportunities, building cultural competency among our employees and positively impacting the business.

Training and Professional Development

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 with the skills that we will need. AEP has a growing co-op and internship program for high school and college students. Our alliances with community colleges, universities and vocational and technical schools across our 11-state service territory support the development of our talent pipeline. We work with these institutions to develop academic programs that will prepare students for new jobs and career opportunities in our industry. AEP also provides a broad range of training and assistance that supports lifelong learning and transition development. This is especially important as we move closer toward a digital future that requires a more flexible, innovative and diverse workforce. AEP has robust processes to achieve this, including ongoing performance coaching, operational skills training, resources to support our commitment to environment, safety and health, job progression training, tuition assistance, and other forms of training that help employees improve their skills and become better leaders.

In 2023, AEP employees completed more than 806,000 hours of training in programs for which we track participation. In addition, AEP invested more than $2 million in employee education, supporting approximately 560 employees through our tuition reimbursement program.

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 that support our employees and their families to help them thrive at home and work. We ensure the pay we offer is competitive in the marketplace by pricing many of our positions using robust compensation survey information. Nearly all AEP employees participate in an annual incentive program that rewards individual performance and achievement of business goals, which fosters a high-performance culture. AEP also offers paid time off in the form of vacation, holidays, sick time and parental leave. The company’s employee assistance plan, medical and dental coverage, life insurance and well-being program help employees and their families stay healthy and feeling their best. Additionally, AEP’s retirement programs position our employees for financial stability in retirement.

Labor Relations

Nearly one fourth of AEP’s workforce is represented by labor unions. We value the relationships we have with our union represented employees and believe in a trusting, collaborative and respectful partnership. We continuously work to strengthen these relationships to ensure we have a culture that attracts and supports employees who can adapt to the rapid changes occurring in our company and industry. Our relationship with labor unions is critical to meeting the growing expectations of our customers and adapting to the challenges of rapidly changing technologies.

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. 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 included in the 2023 Annual Report 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. In Texas, 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, 2023, AEP’s vertically integrated public utility subsidiaries owned approximately 23,000 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:

			2023						2022						2021
Coal and Lignite			37%						43%						50%
Nuclear			22%						21%						22%
Natural Gas			22%						19%						16%
Renewables			19%						17%						12%

An increase/decrease in one or more generation types relative to previous years reflects the addition of renewable resources, retirement of traditional fossil fuel units and price changes in one or more fuel commodity sources relative to the pricing of other fuel commodity sources. AEP’s overall 2023 fossil fuel costs for the Vertically Integrated Utilities decreased 28.3% on a dollar per MMBtu basis from 2022.

Coal and Lignite

AEP’s Vertically Integrated Utilities procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers, marketers and coal trading firms. Coal and lignite consumption decreased 23.9% in 2023 (exclusive of fuel oil) from 2022 due to a combination of the retirement of the Pirkey Power Plant in March 2023 and lower generation at the coal fired power plants due to a significant decline in natural gas prices. AEP’s Vertically Integrated Utilities operations no longer use lignite as a fuel source after the retirement of the Pirkey Power Plant.

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, 2023, through subsidiaries, AEP owns, leases or controls 3,180 railcars, 319 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.

The market price for coal began 2023 elevated as compared to recent years, but declined and stabilized as the year progressed. Although the price of coal in 2023 was lower as compared to 2021 and 2022, the price of coal in 2023 is still higher than historical prices prior to 2021. Coal prices are currently projected to remain at these levels due to increased mining costs experienced over the last few years. AEP’s strategy for purchasing coal includes layering in supplies over time to help with reducing price volatility. The price impact of this process is reflected in subsequent years when the coal is delivered. The price paid for coal and lignite delivered in 2023 increased approximately 14.5% from 2022 mainly due to the increase in coal prices contracted in prior years. With the elevated prices for coal contracted in 2021 and 2022, management anticipates that delivered coal prices will continue to be higher over the next few years.

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:

			2023						2022						2021
Total coal and lignite delivered to the plants (in millions of tons)			20.9						20.4						18.2
Average cost per ton of coal and lignite delivered			$	64.31					$	56.16					$	50.76

The coal supplies at the Vertically Integrated Utilities plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, coal consumption rates, labor issues, supplier outages and issues and weather conditions, all of which may interrupt or slow production, consumption or deliveries. As of December 31, 2023, the Vertically Integrated Utilities’ coal inventory was approximately 82 days of full load burn. Inventory levels grew significantly in 2023 due to mild weather conditions, lower demand for electric power and a decline in natural gas prices. Management expects inventory levels to remain elevated in 2024 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 34 days of full load burn.

Natural Gas

The Vertically Integrated Utilities consumed approximately 146 billion cubic feet of natural gas during 2023 for generating power. This represents an increase of 15.8% from 2022. Several of AEP’s natural gas-fired power plants are connected to at least two pipelines which allow greater access to competitive supplies and improve delivery reliability. From a natural gas supply perspective, the Vertically Integrated Utilities utilize daily spot market purchases, as well as longer-term arrangements including monthly baseload, forward month baseload, seasonal baseload and long-term firm purchases. From a natural gas transportation perspective, the Vertically Integrated Utilities utilize firm and interruptible transportation capacity. AEP’s natural gas supply, transportation and storage transactions are competitively bid and are based on current 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:

			2023						2022						2021
Total natural gas delivered to the plants (in billions cubic feet)			146.0						126.0						108.0
Average delivered price per MMBtu of purchased natural gas			$	2.69					$	6.94					$	8.92

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 and mid-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 is currently evaluating applying for license extensions for both units.

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 2021. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant was $2.2 billion in 2021 non-discounted dollars, with additional ongoing estimated costs of $7 million per year for post decommissioning storage of SNF and an eventual estimated cost of $33 million for the subsequent decommissioning of the spent fuel storage facility, also in 2021 non-discounted dollars. As of December 31, 2023 and 2022, the total decommissioning trust fund balance for the Cook Plant was approximately $3.5 billion and $3 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 included in the 2023 Annual Report 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, 2023, counterparties posted approximately $36 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 $200 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 included in the 2023 Annual Report 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 power (and the energy associated therewith) 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 2024, 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 16 - 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 17 - 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. See Item 1. Business – Vertically Integrated Utilities – Regulation – Rates. 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. For a discussion of competition in the sale of power, see Item 1. Business – Vertically Integrated Utilities – Competition.

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 OATT filed with the FERC and the rules of the FERC relating to such tariff. Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement. The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT. These allocations have been 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 included in the 2023 Annual Report for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a forecasted cost-of-service basis. Indiana provides for timely fuel and purchased power cost recovery through respective fuel and purchased power recovery mechanisms.

Oklahoma

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

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 costs through a fuel cost recovery mechanism. In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses including transmission services provided at OATT rates based on rates established by the FERC.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. West Virginia generally allows for timely recovery of fuel costs, purchased power costs and transmission expenses through the ENEC which trues-up to actual expenses. See “ENEC Filings” section of Note 4 - Rate Matters included in the 2023 Annual Report for additional information. In addition to base rates and fuel cost recovery, APCo and WPCo are permitted to recover a variety of costs through surcharges.

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.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP’s competitiveness.

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, 2023, the State Transcos had $14.2 billion of transmission and other assets in-service, excluding CWIP, with plans to construct approximately $3.4 billion of additional transmission assets through 2026.

AEPTHCO JOINT VENTURE INITIATIVES

AEP has established joint ventures with non-affiliated 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:

Joint Venture Name						Location						Projected or Actual Completion Date						Owners (Ownership %)						Total Estimated/Actual Project Costs at Completion									Approved Return on Equity
																								(in millions)
ETT						Texas						(a)						BHE (50%)						$	5,000.0		(a)						9.6		%
						(ERCOT)												AEP (50%)
Prairie Wind						Kansas						2014						Evergy, Inc. (50%)						158.0									12.8		%
																		BHE (25%)
																		AEP (25%)
Pioneer						Indiana						2018						Duke Energy (50%)						191.0									10.52		%	(b)
																		AEP (50%)
Transource						Missouri						2016						Evergy, Inc. (13.5%) (d)						310.1									11.1		%	(c)
Missouri																		AEP (86.5%) (d)
Transource						West						2019						Evergy, Inc. (13.5%) (d)						84.3									10.5		%
West Virginia						Virginia												AEP (86.5%) (d)
Transource						Maryland						2027						Evergy, Inc. (13.5%) (d)						27.6			(e)						10.4		%
Maryland																		AEP (86.5%) (d)
Transource						Pennsylvania						2027						Evergy, Inc. (13.5%) (d)						243.6			(e)						10.4		%
Pennsylvania																		AEP (86.5%) (d)
Transource						Oklahoma						2026						Evergy, Inc. (13.5%) (d)						127.9			(f)						10.3		%
Oklahoma																		AEP (86.5%) (d)
Transource						Pennsylvania						2027						Evergy, Inc. (13.5%) (d)						104.1			(g)						10.4		%
Energy																		AEP (86.5%) (d)

(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%).

(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 $247 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 with 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 2026.

(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 is expected to go in-service in 2027. The project was originally expected to go in-service in 2029.

In April 2023, AEP initiated a strategic evaluation for its ownership in Pioneer Transmission, LLC, Prairie Wind Transmission, LLC and Transource Energy. In July 2023, AEP made a decision to initiate a sales process for its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC. In February 2024, AEP management determined it would retain its ownership of its investment in Pioneer Transmission, LLC and Prairie Wind Transmission, LLC.

As of December 31, 2023, the net book value of Transource Energy was $289 million inclusive of $39 million related to noncontrolling interest on AEP’s balance sheet. AEP management recently completed its strategic review and determined it would retain this business due to its fit within the goals and objectives of AEP and its overall leadership role in the U.S. electric transmission space.

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 2023, approximately 494 AEPSC employees and 317 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 rate base filings described above, the State Transcos in aggregate filed rate base totals of $10.7 billion, $9.9 billion and $8.4 billion for 2023, 2022 and 2021, respectively. The total filed transmission revenue requirements, including prior year over/under-recovery of revenue and associated carrying charges were $1.8 billion, $1.7 billion and $1.4 billion for 2023, 2022 and 2021, 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 subsidiaries consist of a wholesale energy trading and marketing business, a retail supply and energy management business and competitive generating assets.

AEP Energy Supply, LLC is a holding company with several divisions, including AEP Energy, AEP OnSite Partners, AEPEP and AGR. AEP Energy Supply, LLC also included AEP Renewables prior to its sale in August 2023. For more information on the sale of AEP Renewables, see the “Contracted Renewable Generation Facilities” section of Management’s Discussion and Analysis.

AEP OnSite Partners works directly with wholesale and large retail customers to provide tailored solutions to reduce their energy costs based upon market knowledge, innovative applications of technology and deal structuring capabilities. AEP OnSite Partners targets opportunities in distributed solar, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other energy solutions that create value for customers. AEP OnSite Partners pursues and develops behind the meter projects with creditworthy customers. As of December 31, 2023, AEP OnSite Partners owned projects located in 22 states, including approximately 195 MWs of installed solar capacity, and approximately 4 MWs of solar projects under construction.

AEP Energy is a retail energy supplier and energy management business that supplies electricity and/or natural gas to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 929,000 customer accounts as of December 31, 2023.

In April 2023, AEP announced the initiation of a sales process for its ownership in AEP Onsite Partners and AEP Energy. The timing of the completion of the sales process is dependent upon a number of factors, but AEP is targeting the completion of the sales process in the first half of 2024. For more information, see the “2023 Significant Developments and Transactions” section of Management’s Discussion and Analysis.

AEP Energy Partners enters into short-term and long-term transactions to buy or sell capacity, energy and ancillary services in ERCOT, SPP, MISO and PJM. In addition, AEP Energy Partners sells power into the market and engages in power, natural gas and emissions allowances risk management and trading activities. These activities primarily involve the purchase-and-sale of electricity (and to a lesser extent, natural gas and emissions allowances) under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. The majority of forward contracts are typically settled by entering into offsetting contracts. These transactions are executed with numerous counterparties or on exchanges.

The Generation & Marketing segment also includes AGR which holds the 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.

Changes in regulatory policies and advances in newer technologies for batteries or energy storage, fuel cells, microturbines, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production. The ability to maintain relatively low cost, efficient and reliable operations and to provide cost-effective programs and services to customers are significant determinants of AEP Onsite Partner’s competitiveness. The costs of photovoltaic solar cells in particular have continued to become increasingly competitive.

AEP Energy provides competitive electricity and natural gas in deregulated retail energy markets in six states and Washington, D.C. Each such retail choice jurisdiction establishes its own laws and regulations governing its competitive market, and public utility commission communications and utility default service pricing can affect customer participation in retail competition. Sustained low natural gas and power prices, 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, 2023, counterparties posted approximately $117 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 $155 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 included in the 2023 Annual Report for additional information.

INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following persons are executive officers of AEP. Their ages are given as of February 26, 2024. The officers are appointed annually for a one-year term by the board of directors of AEP.

Benjamin G.S. Folke, III

Interim Chief Executive Officer and President

Age 65

Interim Chief Executive Officer and President since February 2024. Director since February 2022. Chairman of the board of directors of Xcel Energy Inc. from August 2011 to December 2021. Chief Executive Officer of Xcel Energy Inc. from August 2011 to August 2021. President of Xcel from August 2011 to March 2020. Chief Executive Officer of Xcel’s utility subsidiaries Northern States Power Company, Public Service Company of Colorado and Southwestern Public Service Co. from January 2015 to August 2021.

Christian T. Beam

Executive Vice President - Energy Services

Age 55

Executive Vice President - Energy Services since September 2022. President and Chief Operating Officer of APCo from January 2017 to September 2022. Vice President, Projects Controls & Construction from January 2013 to December 2016.

David M. Feinberg

Executive Vice President, General Counsel and Secretary

Age 54

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

Greg B. Hall

Executive Vice President and Chief Commercial Officer

Age 51

Executive Vice President and Chief Commercial Officer since September 2022. Executive Vice President - Energy Supply from July 2021 to September 2022. President and Chief Operating Officer of AEP Energy Supply LLC since July 2021. President of AEP Energy, Inc. since May 2017.

Therace M. Risch

Executive Vice President and Chief Information & Technology Officer

Age 50

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

Peggy I. Simmons

Executive Vice President - Utilities

Age 46

Executive Vice President - Utilities since September 2022. President and Chief Operating Officer of PSO from September 2018 to September 2022.

Antonio P. Smyth

Executive Vice President - Grid Solutions & Government Affairs

Age 47

Executive Vice President - Grid Solutions & Government Affairs since April 2023. 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 53

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. Senior Vice President, Human Resources, Electrical Sector of Eaton from August 2016 to May 2019.

Charles E. Zebula

Executive Vice President - Chief Financial Officer

Age 63

Executive Vice President and Chief Financial Officer since September 2023. Executive Vice President - Portfolio Optimization from July 2021 to September 2023. Executive Vice President - Energy Supply from January 2013 to July 2021.