# EDGAR Filing Document

**Accession Number:** 0000004904
**File Stem:** 0001193125-23-074695
**Filing Date:** 2023-3
**Character Count:** 408918
**Document Hash:** e5c016920e24ad150b517bdd7621e119
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001193125-23-074695.hdr.sgml**: 20230320

**ACCESSION NUMBER**: 0001193125-23-074695

**CONFORMED SUBMISSION TYPE**: ARS

**PUBLIC DOCUMENT COUNT**: 1

**CONFORMED PERIOD OF REPORT**: 20221231

**FILED AS OF DATE**: 20230320

**DATE AS OF CHANGE**: 20230320

**EFFECTIVENESS DATE**: 20230320

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** AMERICAN ELECTRIC POWER CO INC
- **CENTRAL INDEX KEY:** 0000004904
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **IRS NUMBER:** 134922640
- **STATE OF INCORPORATION:** NY
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** ARS
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-03525
- **FILM NUMBER:** 23745985

**BUSINESS ADDRESS:**
- **STREET 1:** 1 RIVERSIDE PLAZA
- **CITY:** COLUMBUS
- **STATE:** OH
- **ZIP:** 43215
- **BUSINESS PHONE:** 614-716-1000

**MAIL ADDRESS:**
- **STREET 1:** 1 RIVERSIDE PLAZA
- **CITY:** COLUMBUS
- **STATE:** OH
- **ZIP:** 43215

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** KINGSPORT UTILITIES INC
- **DATE OF NAME CHANGE:** 19660906

### Attached PDF Documents

**Attachment 1:** `d372544dars.pdf`

Appendix A to the
Proxy Statement

# American Electric Power

## 2022 Annual Report

Audited Consolidated Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations

![img-0.jpeg](img-0.jpeg)

BOUNDLESS ENERGYTM

AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373

# **CONTENTS**

| Glossary of Terms | i |
| --- | --- |
| Forward-Looking Information | vii |
| AEP Common Stock Information | ix |
| Management's Discussion and Analysis of Financial Condition and Results of Operations | 1 |
| Report of Independent Registered Public Accounting Firm | 70 |
| Management's Report on Internal Control Over Financial Reporting | 74 |
| Consolidated Statements of Income | 75 |
| Consolidated Statements of Comprehensive Income (Loss) | 76 |
| Consolidated Statements of Changes in Equity | 77 |
| Consolidated Balance Sheets | 78 |
| Consolidated Statements of Cash Flows | 80 |
| Index of Notes to Financial Statements of Registrants | 81 |
| Corporate and Shareholder Information | 281 |
| Executive Leadership Team | 282 |

2

# GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

| Term | Meaning |
| --- | --- |
| AEGCo | AEP Generating Company, an AEP electric utility subsidiary. |
| AEP | American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned consolidated subsidiaries and consolidated affiliates. |
| AEP Credit | AEP Credit, Inc., a consolidated VIE of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies. |
| AEP East Companies | APCo, I&M, KGPCo, KPCo, OPCo and WPCo. |
| AEP Energy | AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. |
| AEP Energy Supply, LLC | A nonregulated holding company for AEP's competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP. |
| AEP OnSite Partners | A division of AEP Energy Supply, LLC that builds, owns, operates and maintains customer solutions utilizing existing and emerging distributed technologies. |
| AEP Renewables | A division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties. |
| AEP System | American Electric Power System, an electric system, owned and operated by AEP subsidiaries. |
| AEP Texas | AEP Texas Inc., an AEP electric utility subsidiary. |
| AEP Transmission Holdco | AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP. |
| AEP Wind Holdings, LLC | Acquired in April 2019 as Sempra Renewables LLC, develops, owns and operates, or holds interests in, wind generation facilities in the United States. |
| AEPEP | AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in deregulated markets. |
| AEPRO | AEP River Operations, LLC, a commercial barge operation sold in November 2015. |
| AEPSC | American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries. |
| AEPTCo | AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos. |
| AEPTCo Parent | AEP Transmission Company, LLC, the holding company of the State Transcos within the AEPTCo consolidation. |
| AEPTHCo | AEP Transmission Holding Company, LLC, a subsidiary of AEP, an intermediate holding company that owns transmission operations joint ventures and AEPTCo. |
| AFUDC | Allowance for Equity Funds Used During Construction. |
| AGR | AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment. |
| ALJ | Administrative Law Judge. |
| AOCI | Accumulated Other Comprehensive Income. |
| APCo | Appalachian Power Company, an AEP electric utility subsidiary. |
| Appalachian Consumer Rate Relief Funding | Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance. |
| APTCo | AEP Appalachian Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |

i

| Term | Meaning |
| --- | --- |
| APSC | Arkansas Public Service Commission. |
| ARAM | Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes. |
| ARO | Asset Retirement Obligations. |
| ASU | Accounting Standards Update. |
| ATM | At-the-Market. |
| CAA | Clean Air Act. |
| CARES Act | Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020. |
| CCR | Coal Combustion Residual. |
| CLECO | Central Louisiana Electric Company, a nonaffiliated utility company. |
| CO 2 | Carbon dioxide and other greenhouse gases. |
| CO 2e | Carbon dioxide equivalent. |
| Conesville Plant | A retired, single unit coal-fired generation plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-owned by AGR and a nonaffiliate. |
| Cook Plant | Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant owned by I&M. |
| COVID-19 | Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic. |
| CRES provider | Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service. |
| CSAPR | Cross-State Air Pollution Rule. |
| CSPCo | Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011. |
| CWA | Clean Water Act. |
| CWIP | Construction Work in Progress. |
| DCC Fuel | DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV, DCC Fuel XVI, DCC Fuel XVII and DCC Fuel XVIII consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. |
| Desert Sky | Desert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest. |
| DHLC | Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. |
| DIR | Distribution Investment Rider. |
| DOE | U. S. Department of Energy. |
| EIS | Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP. |
| ELG | Effluent Limitation Guidelines. |
| ENEC | Expanded Net Energy Cost. |
| Equity Units | AEP’s Equity Units issued in August 2020 and March 2019. |
| ERCOT | Electric Reliability Council of Texas regional transmission organization. |
| ESP | Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO. |
| ETT | Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT. |
| Excess ADIT | Excess accumulated deferred income taxes. |
| FAC | Fuel Adjustment Clause. |
| FASB | Financial Accounting Standards Board. |
| Federal EPA | United States Environmental Protection Agency. |
| FERC | Federal Energy Regulatory Commission. |

ii

| Term | Meaning |
| --- | --- |
| FGD | Flue Gas Desulfurization or scrubbers. |
| FIP | Federal Implementation Plan. |
| FTR | Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices. |
| GAAP | Accounting Principles Generally Accepted in the United States of America. |
| GHG | Greenhouse gas. |
| I&M | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
| IMTCo | AEP Indiana Michigan Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
| IRA | On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA). |
| IRS | Internal Revenue Service. |
| ITC | Investment Tax Credit. |
| IURC | Indiana Utility Regulatory Commission. |
| KGPCo | Kingsport Power Company, an AEP electric utility subsidiary. |
| KPCo | Kentucky Power Company, an AEP electric utility subsidiary. |
| KPSC | Kentucky Public Service Commission. |
| KTCo | AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
| kV | Kilovolt. |
| KWh | Kilowatt-hour. |
| Liberty | Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corporation. |
| LPSC | Louisiana Public Service Commission. |
| MATS | Mercury and Air Toxic Standards. |
| Maverick | Maverick, part of the North Central Wind Energy Facilities, consists of 287 MWs of wind generation in Oklahoma. |
| MISO | Midcontinent Independent System Operator. |
| Mitchell Plant | A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo. |
| MMBtu | Million British Thermal Units. |
| MPSC | Michigan Public Service Commission. |
| MTM | Mark-to-Market. |
| MW | Megawatt. |
| MWh | Megawatt-hour. |
| NAAQS | National Ambient Air Quality Standards. |
| NERC | North American Electric Reliability Corporation. |
| Nonutility Money Pool | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. |
| NCWF | North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,484 MWs of wind generation. |
| NOL | Net operating losses. |
| NOLC | Net operating loss carryforwards. |
| NO x | Nitrogen oxide. |
| NPDES | National Pollutant Discharge Elimination System. |
| NRC | Nuclear Regulatory Commission. |
| NSR | New Source Review. |

iii

| Term | Meaning |
| --- | --- |
| OATT | Open Access Transmission Tariff. |
| OCC | Corporation Commission of the State of Oklahoma. |
| ODFA | Oklahoma Development Finance Authority. |
| OHTCo | AEP Ohio Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
| Oklaunion Power Station | A retired, single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant was jointly-owned by AEP Texas, PSO and certain nonaffiliated entities. |
| OKTCo | AEP Oklahoma Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
| OPCo | Ohio Power Company, an AEP electric utility subsidiary. |
| OPEB | Other Postretirement Benefits. |
| Operating Agreement | Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales. AEPSC acts as the agent. |
| OTC | Over-the-counter. |
| OVEC | Ohio Valley Electric Corporation, which is 43.47% owned by AEP. |
| Parent | American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation. |
| PATH-WV | PATH West Virginia Transmission Company, LLC, a joint venture-owned 50% by FirstEnergy and 50% by AEP. |
| PCA | Power Coordination Agreement among APCo, I&M, KPCo and WPCo. |
| PFD | Proposal for Decision. |
| PJM | Pennsylvania - New Jersey - Maryland regional transmission organization. |
| PM | Particulate Matter. |
| PPA | Purchase Power and Sale Agreement. |
| PSA | Purchase and Sale Agreement. |
| PSO | Public Service Company of Oklahoma, an AEP electric utility subsidiary. |
| PTC | Production Tax Credit. |
| PUCO | Public Utilities Commission of Ohio. |
| PUCT | Public Utility Commission of Texas. |
| Racine | A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and formerly owned by AGR. Racine was sold to a nonaffiliate in December 2021. |
| Registrant Subsidiaries | AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo. |
| Registrants | SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo. |
| REP | Texas Retail Electric Provider. |
| Restoration Funding | AEP Texas Restoration Funding LLC, a wholly-owned subsidiary of AEP Texas and a consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to storm restoration in Texas primarily caused by Hurricane Harvey. |
| Risk Management Contracts | Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges. |
| Rockport Plant | A generation plant, jointly-owned by AEGCo and I&M, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. |
| ROE | Return on Equity. |
| RPM | Reliability Pricing Model. |
| RTO | Regional Transmission Organization, responsible for moving electricity over large interstate areas. |

iv

| Term | Meaning |
| --- | --- |
| Sabine | Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo. |
| Santa Rita East | Santa Rita East Wind Holdings, LLC, a consolidated VIE whose sole purpose is to own and operate a 302 MW wind generation facility in west Texas in which AEP owns an 85% interest. |
| SEC | U.S. Securities and Exchange Commission. |
| Sempra Renewables LLC | Sempra Renewables LLC, acquired in April 2019 (subsequently renamed as AEP Wind Holdings LLC), consists of 724 MWs of wind generation and battery assets in the United States. |
| SIA | System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP. |
| SIP | State Implementation Plan. |
| SNF | Spent Nuclear Fuel. |
| SO 2 | Sulfur dioxide. |
| SPP | Southwest Power Pool regional transmission organization. |
| SSO | Standard service offer. |
| State Transcos | AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, which are geographically aligned with AEP’s existing utility operating companies. |
| Sundance | Sundance, acquired in April 2021 as part of the North Central Wind Energy Facilities, consists of 199 MWs of wind generation in Oklahoma. |
| SWEPCo | Southwestern Electric Power Company, an AEP electric utility subsidiary. |
| SWTCo | AEP Southwestern Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
| TA | Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent. |
| Tax Reform | On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018. |
| TCA | Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries. |
| Transition Funding | AEP Texas Central Transition Funding III LLC, a wholly-owned subsidiary of AEP Texas and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to restructuring legislation in Texas. |
| Transource Energy | Transource Energy, LLC, a consolidated VIE formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. |
| Traverse | Traverse, part of the North Central Wind Energy Facilities, consists of 998 MWs of wind generation in Oklahoma. |
| Trent | Trent Wind Farm LLC, a 156 MW wind electricity generation facility located in west Texas in which AEP owns a 100% interest. |
| Turk Plant | John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo. |
| UMWA | United Mine Workers of America. |
| UPA | Unit Power Agreement. |
| Utility Money Pool | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. |
| VIE | Variable Interest Entity. |
| Virginia SCC | Virginia State Corporation Commission. |

v

| Term | Meaning |
| --- | --- |
| WPCo | Wheeling Power Company, an AEP electric utility subsidiary. |
| WVPSC | Public Service Commission of West Virginia. |
| WVTCo | AEP West Virginia Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |

vi

# FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Many forward-looking statements appear in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

- • Changes in economic conditions, electric market demand and demographic patterns in AEP service territories.
- • The impact of pandemics and any associated disruption of AEP’s business operations due to impacts on economic or market conditions, costs of compliance with potential government regulations, electricity usage, supply chain issues, customers, service providers, vendors and suppliers.
- • The economic impact of increased global trade tensions including the conflict between Russia and Ukraine, and the adoption or expansion of economic sanctions or trade restrictions.
- • Inflationary or deflationary interest rate trends.
- • Volatility and disruptions in financial markets precipitated by any cause, including failure to make progress on federal budget or debt ceiling matters; particularly developments affecting the availability or cost of capital to finance new capital projects and refinance existing debt.
- • The availability and cost of funds to finance working capital and capital needs, particularly (i) if expected sources of capital, such as proceeds from the sale of assets or subsidiaries, do not materialize or do not materialize at the level anticipated, and (ii) during periods when the time lag between incurring costs and recovery is long and the costs are material.
- • Decreased demand for electricity.
- • Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.
- • The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF.
- • The availability of fuel and necessary generation capacity and the performance of generation plants.
- • The ability to recover fuel and other energy costs through regulated or competitive electric rates.
- • The ability to transition from fossil generation and the ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs.
- • New legislation, litigation or government regulation, including changes to tax laws and regulations, oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or PM and other substances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.
- • The impact of federal tax legislation on results of operations, financial condition, cash flows or credit ratings.
- • The risks before, during and after generation of electricity associated with the fuels used or the byproducts and wastes of such fuels, including coal ash and SNF.
- • Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
- • Resolution of litigation.
- • The ability to constrain operation and maintenance costs.
- • Prices and demand for power generated and sold at wholesale.

vii

- • Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of generation.
- • The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
- • Volatility and changes in markets for coal and other energy-related commodities, particularly changes in the price of natural gas.
- • The impact of changing expectations and demands of customers, regulators, investors and stakeholders, including heightened emphasis on environmental, social and governance concerns.
- • Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
- • Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market.
- • Actions of rating agencies, including changes in the ratings of debt.
- • The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.
- • Accounting standards periodically issued by accounting standard-setting bodies.
- • Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber-security threats and other catastrophic events.
- • The ability to attract and retain the requisite work force and key personnel.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. The Registrants expressly disclaim any obligation to update any forward-looking information, except as required by law. For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

The Registrants may use AEP’s website as a distribution channel for material company information. Financial and other important information regarding the Registrants is routinely posted on and accessible through AEP’s website at www.aep.com/investors/. In addition, you may automatically receive email alerts and other information about the Registrants when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.

viii

# AEP COMMON STOCK INFORMATION

AEP common stock is principally traded using the trading symbol “AEP” on the NASDAQ Stock Market. As of December 31, 2022, AEP had 51,279 registered shareholders. The performance graph below compares the cumulative total return among AEP, the S&P 500 Index and the S&P Electric Utilities (SP833) Index over a five year period. The performance graph assumes an initial investment of $100 on December 31, 2017 and that all dividends were reinvested.

![img-0.jpeg](img-0.jpeg)

Source: S&P Dow Jones Indices LLC. Data as of December 31, 2022. Past performance is no guarantee of future results. Chart provided for illustrative purposes.

ix

# AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

# EXECUTIVE OVERVIEW

# Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States. AEP's electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP's subsidiaries operate an extensive portfolio of assets including:

- Approximately 225,000 circuit miles of distribution lines that deliver electricity to 5.6 million customers.
- Approximately 40,000 circuit miles of transmission lines, including approximately 2,200 circuit miles of 765 kV lines, the backbone of the electric interconnection grid in the eastern United States.
- Approximately 23,500 MWs of regulated owned generating capacity as of December 31, 2022, one of the largest complements of generation in the United States.

# Customer Demand

AEP's weather-normalized retail sales volumes for the year ended December 31, 2022 increased by 2.8% from the year ended December 31, 2021. Weather-normalized residential sales increased 0.1% for the year ended December 31, 2022 compared to the year ended December 31, 2021. Weather-normalized commercial sales increased by 4.2% in 2022 compared to 2021. The increase in commercial sales was spread across many sectors. AEP's 2022 industrial sales volumes increased 4.5% compared to 2021. The growth in industrial sales was spread across many industries.

In 2023, AEP anticipates weather-normalized retail sales volumes will increase by 0.7%. Weather-normalized residential sales volumes are projected to decrease by 0.5% in 2023, while weather-normalized commercial sales volumes are projected to increase by 0.6%. Finally, AEP projects the industrial class to increase by 2.1% in 2023.

![img-1.jpeg](img-1.jpeg)

(a) Percentage change for the year ended December 31, 2022 as compared to the year ended December 31, 2021.

(b) Forecasted percentage change for the year ended December 31, 2023 compared to the year ended December 31, 2022.

1

### ***Supply Chain Disruption and Inflation***

The Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, international tensions including the ramifications of regional conflict, increased demand due to the economic recovery from the pandemic, inflation, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions.

The United States economy has experienced a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. A prolonged continuation or a further increase in the severity of supply chain and inflationary disruptions could result in additional increases in the cost of certain goods, services and cost of capital and further extend lead times which could reduce future net income and cash flows and impact financial condition.

### ***Strategic Evaluation of AEP Energy***

AEP has initiated a strategic evaluation for its ownership in AEP Energy, a wholly-owned retail energy supplier 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 736,000 customer accounts as of December 31, 2022. Potential alternatives may include, but are not limited to, continued ownership or a sale of all or a part of AEP Energy. Management has not made a decision regarding the potential alternatives, but expects to complete the strategic evaluation in the first half of 2023.

### ***Regulatory Matters***

AEP's public utility subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Depending on the outcomes, these rate and regulatory proceedings can have a material impact on results of operations, cash flows and possibly financial condition. AEP is currently involved in the following key proceedings. See Note 4 - Rate Matters for additional information.

- *2017-2019 Virginia Triennial Review* - In November 2020, the Virginia SCC issued an order on APCo's 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo's appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band.

In response to the Virginia Supreme Court's August 2022 opinion, the Virginia SCC initiated remand proceedings and, in December 2022, issued an order that: (a) approved APCo's requested $37 million regulatory asset related to previously incurred costs as a result of APCo earning below its 2017-2019 authorized ROE band, (b) authorized a $28 million annual increase in APCo Virginia base rates effective

2

October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s 2022 financial statements reflect the impact of the Virginia SCC’s December 2022 order.

- *2020-2022 Virginia Triennial Review* - In March 2023, APCo will submit its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period.

APCo is also required to submit a depreciation study as part of its 2020-2022 Triennial Review filing based on plant in service balances as of December 31, 2022. APCo is required to implement the impacts of this depreciation study effective January 1, 2023 without a corresponding adjustment in customer rates until the first quarter of 2024. While subject to review as part of APCo’s 2020-2022 Virginia Triennial Review, a significant change in depreciation rates (either an increase or a decrease) without a corresponding adjustment in Virginia retail rates would impact future net income and cash flows and impact financial condition.

- *2012 Texas Base Rate Case* - In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.

In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of December 31, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $185 million related to revenues collected from February 2013 through December 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

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- In July 2019, Ohio House Bill 6 (HB 6), which offered incentives for power-generating facilities with zero or reduced carbon emissions, was signed into law by the Ohio Governor. HB 6 terminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for continued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which is allocated to all electric distribution utility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty and a criminal trial is proceeding against the other. In 2021, four AEP shareholders filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors. See “Litigation Related to Ohio House Bill 6” section of Litigation below for additional information.

In March 2021, the Governor of Ohio signed legislation that, among other things, repealed the payments to the nonaffiliated owner of Ohio’s nuclear power plants that were previously authorized under HB 6. The new legislation, House Bill 128, went into effect in May 2021 and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs. To the extent that the law changes or OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or incurs significant costs associated with the derivative actions, it could reduce future net income and cash flows and impact financial condition.

- In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify its incentive for transmission owners that join RTOs (RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be modified such that a utility would only be eligible for the RTO Incentive for the first three years after the utility joins a FERC-approved Transmission Organization. This is a significant departure from a previous NOPR issued in 2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis points. The supplemental NOPR also required utilities that have received the RTO Incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR was subject to a 60-day comment period followed by a 30-day period for reply comments. In July 2021, AEP submitted reply comments. AEP is awaiting a final rule from the FERC.

In 2019, the FERC approved settlement agreements establishing base ROEs of 9.85% (10.35% inclusive of RTO Incentive adder of 0.5%) and 10% (10.5% inclusive of RTO Incentive adder of 0.5%) for AEP’s PJM and SPP transmission-owning subsidiaries, respectively. In 2020, the FERC determined the base ROE for MISO’s transmission owning subsidiaries should be 10.02% (10.52% inclusive of RTO Incentive adder of 0.5%).

If the FERC modifies its RTO Incentive policy, it would be applied, as applicable, to AEP’s PJM, SPP and MISO transmission owning subsidiaries on a prospective basis, and could affect future net income and cash flows and impact financial condition. Based on management’s preliminary estimates, if a final rule is adopted consistent with the April 2021 supplemental NOPR, it could reduce AEP’s pretax income by approximately $35 million to $50 million on an annual basis.

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- • *FERC RTO Incentive Complaint* - In February 2022, the Office of the Ohio Consumers' Counsel (OCC) filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50-basis point RTO incentive included in Ohio Transmission Owners' respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC's February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 0.5 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. A FERC order on rehearing is expected in 2023. Based on management's preliminary estimates, the December 2022 FERC order is expected to reduce AEP's pretax income by approximately $20 million on an annual basis.

In July 2021, the FERC issued an order denying Dayton Power and Light's request for a 50 basis point RTO incentive on the basis that its RTO participation was not voluntary, but rather is required by Ohio law. This precedent could have an adverse impact on AEP's Ohio transmission owning subsidiaries. In its February 2022 order on rehearing, the FERC affirmed the decision in its July 2021 order. The case is currently pending appeal at the U.S. Court of Appeals for the Sixth Circuit. In May 2022, the U.S. Court of Appeals for the Sixth Circuit issued an order to hold the appeal in abeyance pending resolution of FERC proceedings on the Office of the Ohio Consumers' Counsels' February 2022 RTO Incentive Complaint.

- • *2021 Louisiana Storm Cost Filing* - In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected in the first quarter of 2023. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
- • In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP's history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. As a result of the severe winter weather, PSO and SWEPCo incurred approximately $1.1 billion of extraordinary fuel costs and purchases of electricity, which were deferred as regulatory assets.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO's extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO's extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.

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In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudence review and true-up.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

- AEP transitioned to stand-alone treatment of NOLC in its PJM and SPP transmission formula rates beginning with 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the 2021 and 2022 annual revenue requirements by $78 million and $60 million, respectively. Through year-end 2022, the Registrants’ financial statements reflect a provision for refund for certain NOLC revenues billed by PJM and SPP. Also, a certain portion of the impact of inclusion of the NOLC in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses as the Registrants have not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.

AEP is also transitioning to stand-alone treatment of NOLC in retail jurisdiction base rate case filings. As a result of retail jurisdiction base rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates in those jurisdictions is contingent upon a supportive private letter ruling from the IRS. If the Registrant Subsidiaries are successful in transitioning to stand-alone treatment of NOLC, it could have a material, favorable impact on future net income.

- *SPP Capacity Planning Reserve Margin* - In July 2022, SPP approved a plan to increase its capacity planning reserve margin from 12% to 15% starting in the summer of 2023. Compliance filings were made with SPP in February 2023 and any deficiencies are required to be remedied by May 2023. SPP’s annual

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non-compliance charge as a result of not meeting capacity requirements could range from approximately $86 thousand per MW to approximately $171 thousand per MW under the current SPP tariff. Non-compliance could also result in a failure to meet NERC criteria. As of December 31, 2022, the increase in the capacity planning reserve margin for PSO and SWEPCo to comply with this new SPP requirement was approximately 265 MWs.

Management has been taking actions and expects to comply with SPP’s 2023 capacity planning reserve margin requirement. If PSO or SWEPCo incur charges or are unable to recover, or experience delays in recovering, the costs of complying with SPP’s rule, it could reduce future net income and cash flows and impact financial condition.

### *Utility Rates and Rate Proceedings*

The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.

The following tables show the Registrants’ completed and pending base rate case proceedings in 2022. See Note 4 - Rate Matters for additional information.

#### *Completed Base Rate Case Proceedings*

| Company | Jurisdiction | Approved Revenue Requirement Increase (in millions) | Approved ROE | New Rates Effective |
| --- | --- | --- | --- | --- |
| SWEPCo | Texas | $39.4 | 9.25% | March 2021 |
| I&M | Indiana | 61.4 (a) | 9.7% | February 2022 |
| SWEPCo | Arkansas | 48.7 | 9.5% | July 2022 |
| KGPCo | Tennessee | 5.8 | 9.5% | August 2022 |
| SWEPCo | Louisiana | 21.0 | 9.5% | February 2023 |

(a) See “2021 Indiana Base Rate Case” section of Note 4 - Rate Matters in the 2021 Annual Report for additional information.

#### *Pending Base Rate Case Proceedings*

| Company | Jurisdiction | Filing Date | Requested Revenue Requirement Increase (in millions) | Requested ROE | Commission Staff/ Intervenor Range of Recommended ROE |
| --- | --- | --- | --- | --- | --- |
| PSO | Oklahoma | November 2022 | $173.0 | 10.4% | (a) |

(a) Intervenor testimony is expected to be filed in the first quarter of 2023.

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## Deferred Fuel Costs

Increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in most jurisdictions. The table below illustrates the increase (decrease) in the deferred fuel regulatory assets by company and jurisdiction, excluding the impacts of the February 2021 severe winter weather event. See the “February 2021 Severe Winter Weather Impacts in SPP” sections in Note 4 for additional information.

| Company | Jurisdiction | Traditional FAC Recovery Reset | As of December 31, 2022 | As of December 31, 2021 | Increase/ (Decrease) |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
|  |  | APCo | Virginia (a) | Annually | $407.9 | $128.6 | $279.3 |
| APCo | West Virginia | Annually | 288.5 | 72.7 | 215.8 |  |  |
| I&M | Indiana | Bi-Annually | 38.1 | - | 38.1 |  |  |
| I&M | Michigan | Annually | 9.0 | 6.4 | 2.6 |  |  |
| PSO | Oklahoma (b) | Annually | 431.5 | 194.6 | 236.9 |  |  |
| SWEPCo | Arkansas | Annually | 65.8 | 23.1 | 42.7 |  |  |
| SWEPCo | Louisiana | Monthly | - | 11.1 | (11.1) |  |  |
| SWEPCo | Texas | Tri-Annually | 191.4 | 47.0 | 144.4 |  |  |
| KPCo | Kentucky | Monthly | 23.2 | 8.2 | 15.0 |  |  |
| WPCo | West Virginia | Annually | 231.1 | 101.6 | 129.5 |  |  |
|  |  | Total (c) | $1,686.5 | $593.3 | $1,093.2 |  |  |

- (a) Includes $223 million of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets as of December 31, 2022.
- (b) Includes $253 million of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets as of December 31, 2022.
- (c) Includes $23 million and $8 million as of December 31, 2022 and December 31, 2021, respectively, of deferred fuel classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

The AEP utility subsidiaries are working with various state commissions on the timing of recovering deferred fuel balances and have made the following recent filings:

In April 2022, APCo and WPCo submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudence review. See “2021 and 2022 ENEC Filings” section of Note 4 for additional information.

In August 2022, PSO requested an interim update to its annual Fuel Cost Adjustment (FCA) rates in accordance with the terms of the established tariff which allows PSO or the OCC staff to request an interim FCA adjustment in the event that the annual FCA over/under-recovered balance is $50 million or more on a cumulative basis. In September 2022, the Director of the Public Utility Division of the OCC approved a FCA rate designed to collect a $402 million deferred fuel balance over a 27-month period, effective with the first billing cycle of October 2022. PSO’s fuel and purchased power expenses are subject to an annual prudence review by the OCC.

In September 2022, APCo submitted a request to the Virginia SCC to increase its annual fuel factor by approximately $279 million. APCo implemented interim FAC rates effective November 2022 subject to Virginia SCC review. To help mitigate the impact of rising fuel costs on customer bills, APCo proposed to recover its deferred fuel balance as of October 31, 2022 over two years. An order from the Virginia SCC is expected in the first quarter of 2023.

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In September 2022, SWEPCo filed a request with the APSC for an interim increase to its current Energy Cost Rate (ECR) to recover $44 million of additional fuel costs incurred from April 2022 through August 2022, subsequent to the last annual ECR rate change. The interim rate was effective with the first billing cycle of October 2022 and will be in effect for six months until the ECR is reset in April 2023.

In October 2022, SWEPCo filed a request with the PUCT for an interim fuel surcharge to recover $83 million of additional fuel costs incurred through August 2022. An interim rate is effective February 2023, subject to final approval by the PUCT.

### ***Dolet Hills Power Station and Related Fuel Operations***

In 2020, management of SWEPCo and CLECO determined DHLC would not develop additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.

The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through rate riders. As of December 31, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $112 million, including materials and supplies, net of cost of removal collected in rates.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudence determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $32 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $32 million deferral, with refunds to customers over five years. In September 2022, SWEPCo filed rebuttal testimony addressing the LPSC staff recommendations.

In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.

In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021. Intervenor testimony is due in the first quarter of 2023 and a decision from the PUCT is expected in the third quarter of 2023.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

### ***Pirkey Plant and Related Fuel Operations***

In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and rate riders. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider. Fuel costs are recovered through active fuel clauses and are subject to prudence determinations by the various commissions. As of December 31, 2022, SWEPCo’s share of the net investment in the Pirkey Plant is $215 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an

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amount equal to mining costs plus a management fee. SWEPCo expects fuel deliveries, including billings of all fixed and operating costs, from Sabine to cease during the first quarter of 2023. Under the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $43 million as of December 31, 2022. As of December 31, 2022, SWEPCo had a net under-recovered fuel balance of $257 million, inclusive of costs related to Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

### ***Renewable Generation***

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.

### ***Contracted Renewable Generation Facilities***

In recent years, AEP has developed its renewable portfolio within the Generation & Marketing segment. Activities have included working directly with wholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and deal structuring which may include distributed solar, wind, combined heat and power, energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. The Generation & Marketing segment also developed and/or acquired large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. Subsequently, AEP’s investment in Flat Ridge 2 Wind LLC was removed from the competitive contracted renewables sale portfolio. In June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary and recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. In the third quarter of 2022, in accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, AEP recorded an additional $2 million pretax other than temporary impairment charge in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. AEP has recorded a $188 million other than temporary impairment in its investment in Flat Ridge 2 for the year ended December 31, 2022 in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s statements of income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and was based on negotiations to sell the investment to a nonaffiliate. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2. The transaction closed in the fourth quarter of 2022 and had an immaterial impact on the financial statements at closing.

As of December 31, 2022, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in four joint venture wind farms, totaling $247 million, accounted for as equity method investments.

In late January 2023, AEP received final bids from interested parties. In February 2023, AEP’s Board of Directors approved management’s plan to sell the competitive contracted renewables portfolio and AEP signed an agreement to sell the competitive contracted renewables portfolio to a nonaffiliated party for $1.5 billion including the assumption of project debt. As part of the sale agreement, AEP provided the acquirer an indemnification related to certain losses, not to exceed $70 million, which could result from one of the joint venture wind farm’s inability to meet certain minimum performance requirements.

The sale is subject to FERC approval, clearance from the Committee on Foreign Investment in the United States and approval under applicable competition laws. AEP expects to close on the sale in the second quarter of 2023 and

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receive cash proceeds, net of taxes, transaction fees and other customary closing adjustments, of approximately $1.2 billion.

Management concluded the consolidated assets within the competitive contracted renewables portfolio met the accounting requirements to be presented as Held for Sale in the first quarter of 2023 based on the receipt of final bids, Board of Director approval to consummate a sale transaction and the signing of the sale agreement. AEP anticipates recording an estimated pretax loss ranging from $175 million to $225 million ($100 million to $150 million after-tax), in the first quarter of 2023 as a result of reaching Held for Sale status. Management concluded the impact of any other than temporary decline in the fair value of the four joint venture wind farms was not material to AEP’s December 31, 2022 financial statements. Any changes to the book value or carrying value of these assets, or the anticipated sale price, could further reduce future net income and impact financial condition.

### *Regulated Renewable Generation Facilities*

#### *North Central Wind Facilities*

In 2020, PSO and SWEPCo received regulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,484 MWs. PSO and SWEPCo own undivided interests of 45.5% and 54.5% of the NCWF, respectively. Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. The Arkansas portion of the NCWF revenue requirement was approved for recovery through base rates in the 2021 Arkansas base rate case. The table below provides a summary of the facilities as of December 31, 2022:

| Project | In-Service Date | Net Book Value (in millions) | Federal PTC Qualification % (a) | Generating Capacity (in MWs) |
| --- | --- | --- | --- | --- |
| Sundance | April 2021 | $282.3 | 100% | 199 |
| Maverick | September 2021 | 398.3 | 80% | 287 |
| Traverse | March 2022 | 1,255.0 | 100 % (b) | 998 |

(a) PTC benefits are available for a ten year period following the in-service date.

(b) The PTC for Traverse was increased to 100% in the third quarter of 2022 as a result of the IRA legislation.

See “North Central Wind Energy Facilities” section of Note 7 for additional information.

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### *Recent Renewable Generation Filings*

In December 2021 and January 2022, APCo filed petitions with the Virginia SCC and WVPSC, respectively, for prudence and cost recovery of several renewable projects. In July 2022, the Virginia SCC approved APCo’s December 2021 petition for prudence and cost recovery. In January 2023, the WVPSC issued an order approving the remaining projects included in the petition. The table below provides a list of all remaining projects from the APCo petitions.

| Generation Type | Expected Commercial Operation | Owned/PPA | Generating Capacity (in MWs) |
| --- | --- | --- | --- |
| Solar | Second Quarter 2023 | Owned | 5 |
| Solar | Fourth Quarter 2025 | PPA | 20 |
| Solar | In Operation | PPA | 15 |
| Wind | Third Quarter 2025 | Owned | 204 |
| Total Renewable Projects |  |  | 244 |

In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting approval to acquire three renewable energy projects totaling 999 MWs. In October 2022, SWEPCo also submitted the necessary filings with the FERC. The projects are comprised of two wind facilities, totaling 799 MWs, and one solar facility, totaling 200 MWs. One of the wind facilities, totaling approximately 201 MWs, is expected to reach commercial operation in December 2024 with the remaining facilities expected to reach commercial operation in December 2025. In January 2023, a hearing was held at the PUCT. Additionally in January 2023, SWEPCo filed an unopposed joint settlement agreement with the APSC that supported approval of the projects. An order from the APSC is expected in the second quarter of 2023. In December, 2022, an intervenor filed suit seeking injunctive relief to effectively halt SWEPCo’s regulatory proceedings, among other relief; however, the magistrate judge for the United States District Court for the Eastern District of Texas has recommended denial of intervenor’s request for injunctive relief.

In November 2022, PSO submitted filings with the OCC requesting approval of its fuel-free power plan to purchase three new wind farms, totaling approximately 553 MWs, and three new solar facilities, totaling approximately 443 MWs. These projects are expected to reach commercial operation in 2025. This proposed plan will help meet projected power needs while protecting customers from volatility in energy costs driven by high natural gas and power prices. In addition, PSO has recently executed an agreement to purchase the 154 MW Rock Falls Wind Facility, and has requested cost recovery in the 2022 Oklahoma Base Rate Case. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. See “2022 Oklahoma Base Rate Case” section of Note 4 for additional information.

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### *Significant Renewable Generation Requests for Proposal (RFP)*

As part of AEP’s transition to diversify the company’s generation resources and build its renewable generation portfolio, the Registrants file RFPs in an effort to identify potential wind and solar projects. The table below includes RFPs recently issued for owned generation. These projects would be subject to regulatory approval.

| Company | Issuance Date | Generation Type | Generating Capacity (in MWs) |
| --- | --- | --- | --- |
| APCo | January 2022 | Wind | 1,000 |
| APCo | January 2022 | Solar (a) | 100 |
| I&M | March 2022 | Wind (a)(b) | 800 |
| I&M | March 2022 | Solar (a)(b) | 500 |
| SWEPCo | September 2022 | Wind (a) | 1,900 |
| SWEPCo | September 2022 | Solar (a) | 500 |
| Total Significant RFPs |  |  | 4,800 |

(a) Includes an option for battery storage.

(b) Includes solicitation of bids for both owned projects and PPAs.

### *Disposition of KPCo and KTCo*

In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR) and the Committee on Foreign Investment in the United States during 2022. Clearance under the HSR expired in January 2023. AEP and Liberty refiled a joint application seeking HSR clearance in February 2023. The sale is also contingent upon FERC approval under Section 203 of the Federal Power Act. The parties to the SPA have certain termination rights if the closing of the sale does not occur by April 26, 2023.

### *Transfer of Ownership*

#### FERC Proceedings

In December 2021, Liberty, KPCo and KTCo (the applicants) requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have an adverse effect on rates.

In January 2023, AEP, AEPTCo, and Liberty entered into an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. The applicants requested expedited treatment of the new filing, including an accelerated comment period. In response, the FERC granted a shortened 45 day comment period. The applicants believe the new Section 203 application addresses the concerns raised in the FERC’s December 2022 order. The application contains several additional commitments by Liberty to mitigate potential adverse impacts on FERC jurisdictional rates over the next five years, including: a) maintaining the current return on equity; b) maintaining the current cost cap on equity; c) financing future investments at the current credit rating; and d) capping certain operating and administrative costs. The sale remains subject to FERC approval. The statute requires an order from the FERC within 180 days of the February 14, 2023 filing date in accordance with Section 203 of the Federal Power Act.

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## KPSC Proceedings

In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%.

### *Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement*

KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of December 31, 2022 and 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million and $586 million, respectively. The SPA includes a condition precedent to closing requiring the issuance of regulatory orders approving new Mitchell Plant agreements.

The KPSC and WVPSC issued orders proposing materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.

### *Summary*

As a result of the conditions imposed by the KPSC’s May 2022 order, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement.

In September 2022, AEP, AEPTCo and Liberty entered into an amendment to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving new proposed Mitchell Plant agreements. Further, as a result of the reduced purchase price from the September Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement.

As a result of the December 2022 FERC order and resulting delay in the anticipated timing of the closing of the transaction, AEP recorded an additional $100 million pretax loss ($79 million net of tax) on the expected sale of the Kentucky Operations in December 2022 in accordance with the accounting guidance for Fair Value Measurement. In total, AEP recorded a $363 million pretax loss of ($297 million net of tax) on the expected sale of the Kentucky Operations for the twelve months ended December 31, 2022.

Management believes it is probable that FERC authorization under Section 203 of the Federal Power Act will be received and closing will occur after receipt of the order. Therefore, the assets and liabilities of KPCo and KTCo were classified as Held for Sale in the December 31, 2022 balance sheets of AEP and AEPTCo. Upon closing, Liberty will acquire the assets and assume the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion. AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.

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### ***Merchant Portion of Turk Plant***

SWEPCo constructed the Turk Plant, a base load 600 MW (650 MW net maximum capacity) pulverized coal ultra-supercritical generating unit in Arkansas, which was placed in-service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs/477 MWs) of the Turk Plant and operates the facility.

Approximately 20% of the Turk Plant output is currently not subject to cost-based rate recovery in Arkansas. This portion of the plant's output is being sold into the wholesale market. Approximately 80% of the Turk Plant investment is recovered under retail cost-based rate recovery in Texas, Louisiana and through SWEPCo's wholesale customers under FERC-approved rates. In November 2022, SWEPCo filed a Certificate of Public Convenience and Necessity with the APSC for approval to operate the Turk plant to serve Arkansas customers and recover the associated costs through a cost recovery rider. Cost-based recovery of the Turk Plant would aid SWEPCo's near-term capacity needs and support compliance with SPP's 2023 increased capacity planning reserve margin requirements. As of December 31, 2022, the net book value of the Turk Plant was $1.4 billion, before cost of removal including CWIP and inventory. If SWEPCo cannot ultimately recover its investment and expenses related to the Arkansas retail portion of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

### ***Winter Storm Elliott***

In December 2022, severe winter weather and extreme cold temperatures resulted in an unusually high demand for electricity and the declaration of an Energy Emergency Alert (EEA) in the PJM region. The EEA was in effect from December 23, 2022 through December 25, 2022. During this time, all electric generating units located within the PJM region were directed to operate up to their maximum generation output levels. The issuance of the EEA also triggered PJM Performance Assessment Intervals (PAI) for each committed generation capacity resource. During a PAI event, PJM evaluates the performance of each committed capacity resource against PJM performance standards. Generating units that underperform during a PAI event are subject to non-performance charges while generating units that perform above expectations are awarded performance bonuses. PJM awards and allocates the bonus performance payments from the pool of non-performance charges collected during the PAI event. PJM provided preliminary performance standards for each generating resource in January 2023 and additional preliminary generating unit performance data was released by PJM in February 2023. PJM currently expects to invoice non-performance charges and bonus payments in the month-end bill for March 2023 issued in early April 2023. As of December 31, 2022, based on preliminary PJM performance standards and internal generation estimates, OPCo and APCo recorded $7 million and $2 million, respectively, of non-performance charges from the December PAI event in Electricity, Transmission and Distribution revenues and Purchased Electricity, Fuel and Other Consumables Used for Electric Generation, respectively, on the statements of income. The Registrants did not record estimated bonus performance payments as of December 31, 2022 as those amounts were not reasonably estimable.

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# LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihood of loss if the loss can be estimated. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition. See Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies for additional information.

## *Rockport Plant Litigation*

In 2013, the Wilmington Trust Company filed suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.

After the litigation proceeded at the district court and appellate court, in April 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit. The transaction closed at the expiration of the Rockport Plant, Unit 2 lease in December 2022 and also resulted in a final settlement of, and release of claims in, the lease litigation.

Subsequent to the end of the Rockport Plant, Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Plant, Unit 2 is being billed to I&M under a FERC-approved UPA. I&M’s purchased power from AEGCo and I&M’s 50% ownership share of Rockport Plant, Unit 2 electricity generated represent a merchant resource for I&M until Rockport Plant, Unit 2 is retired in 2028. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Plant, Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. The MPSC issued an order in February 2023 approving the settlement agreement on I&M’s 2022 Integrated Resource Plan (IRP) filing, which included certain cost recovery for the remaining net book value of leasehold improvements made during the term of the Rockport Plant, Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Plant Unit 2, it could reduce future net income and cash flows and impact financial condition.

## *Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula*

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to

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dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs filed a motion for leave to file an amended complaint, which the Court denied on December 1, 2022. The plaintiffs did not file an appeal by the deadline of January 3, 2023.

### ***Litigation Related to Ohio House Bill 6 (HB 6)***

In 2019, Ohio adopted and implemented HB 6 which benefits OPCo by authorizing rate recovery for certain costs including renewable energy contracts and OVEC’s coal-fired generating units. OPCo engaged in lobbying efforts and provided testimony during the legislative process in connection with HB 6. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of an Ohio legislator and associates in connection with an alleged racketeering conspiracy involving the adoption of HB 6. After AEP learned of the criminal allegations against the Ohio legislator and others relating to HB 6, AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. Management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.

In August 2020, an AEP shareholder filed a putative class action lawsuit in the U.S. District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleged misrepresentations or omissions by AEP regarding: (a) its alleged participation in or connection to public corruption with respect to the passage of HB 6 and (b) its regulatory, legislative, political contribution, 501(c)(4) organization contribution and lobbying activities in Ohio. The complaint sought monetary damages, among other forms of relief. In December 2021, the district court issued an opinion and order dismissing the securities litigation complaint with prejudice, determining that the complaint failed to plead any actionable misrepresentations or omissions. The plaintiffs did not appeal the ruling.

In January 2021, an AEP shareholder filed a derivative action in the U.S. District Court for the Southern District of Ohio purporting to assert claims on behalf of AEP against certain AEP officers and directors. In February 2021, a second AEP shareholder filed a similar derivative action in the Court of Common Pleas of Franklin County, Ohio. In April 2021, a third AEP shareholder filed a similar derivative action in the U.S. District Court for the Southern District of Ohio and a fourth AEP shareholder filed a similar derivative action in the Supreme Court for the State of New York, Nassau County. These derivative complaints allege the officers and directors made misrepresentations and omissions similar to those alleged in the putative securities class action lawsuit filed against AEP. The derivative complaints together assert claims for: (a) breach of fiduciary duty, (b) waste of corporate assets, (c) unjust enrichment, (d) breach of duty for insider trading and (e) contribution for violations of sections 10(b) and 21D of the Securities Exchange Act of 1934; and seek monetary damages and changes to AEP’s corporate governance and internal policies among other forms of relief. The court entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed substantive and forum-based motions to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the forum-based motion to dismiss with prejudice and the plaintiffs subsequently filed a notice of appeal with the New York appellate court. On January 20, 2023, the New York plaintiff filed a motion to intervene in the pending Ohio federal court action and withdrew his appeal in New York on January 24, 2023. AEP filed a brief in opposition to intervention on February 3, 2023. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint. AEP filed a motion to dismiss the amended complaint on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the consolidated derivative actions pending in Ohio federal district court. The defendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In March 2021, AEP received a litigation demand letter from counsel representing a purported AEP shareholder. The litigation demand letter is directed to the Board of Directors of AEP and contains factual allegations involving HB 6 that are generally consistent with those in the derivative litigation filed in state and federal court. The letter demands, among other things, that the AEP Board undertake an independent investigation into alleged legal violations by directors and officers, and that, following such investigation, AEP commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who

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allegedly harmed the company. The shareholder that sent the letter has since withdrawn the litigation demand, which is now terminated and of no further effect.

In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing investigation. AEP is cooperating fully with the SEC’s investigation, which has included taking testimony from certain individuals. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this investigation will have a material impact on financial condition, results of operations or cash flows.

# ***Claims for Indemnification Related to Damages Resulting from the Federal EPA's Denial of Alternative Closure Deadline for Gavin Plant and Associated Findings of Compliance***

In November 2022, the Federal EPA issued a final decision denying Gavin Power LLC’s requested extension to allow a CCR surface impoundment at the Gavin Power Station to continue to receive CCR and non-CCR waste streams after April 11, 2021 until May 4, 2023 (the Gavin Denial). As part of the Gavin Denial, the Federal EPA made several determinations related to the CCR Rule (see “Coal Combustion Residual (CCR) Rule” section below for additional information), including a determination that the closure of the 300 acre unlined fly ash reservoir (FAR) is noncompliant with the CCR Rule in multiple respects. The Gavin Power Station was formerly owned and operated by AEP and was sold to Gavin Power LLC and Lightstone Generation LLC in 2017. Pursuant to the PSA, AEP maintained responsibility to complete closure of the FAR in accordance with the closure plan approved by the Ohio EPA which was completed in July 2021. The PSA contains indemnification provisions, pursuant to which the owners of the Gavin Power Station have notified AEP they believe they are entitled to indemnification for any damages that may result from the Gavin Denial, as well as any future enforcement or litigation resulting from the Federal EPA’s determinations of noncompliance with various aspects of the CCR Rule as part of the Gavin Denial. Management does not believe that the owners of the Gavin Power Station have any valid claim for indemnity or otherwise against AEP under the PSA. In addition, Gavin Power LLC, several AEP subsidiaries, and other parties have filed Petitions for Review of the Gavin Denial with the U.S. Court of Appeals for the District of Columbia Circuit. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

# **ENVIRONMENTAL ISSUES**

AEP has a substantial capital investment program and incurs additional operational costs to comply with environmental control requirements. Additional investments and operational changes will be made in response to existing and anticipated requirements to reduce emissions from fossil generation and in response to rules governing the beneficial use and disposal of coal combustion by-products, clean water and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites and incurred costs for disposal of SNF and future decommissioning of the nuclear units. Management is engaged in the development of possible future requirements including the items discussed below.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP cannot recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

# ***Environmental Controls Impact on the Generating Fleet***

The rules and proposed environmental controls discussed below will have a material impact on AEP System generating units. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of December 31, 2022, the AEP System owned generating capacity of approximately 25,000 MWs, of which approximately 11,300 MWs were coal-fired. Management continues to

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refine the cost estimates of complying with these rules and other impacts of the environmental proposals on fossil generation. Based upon management estimates, AEP’s future investment to meet these existing and proposed requirements ranges from approximately $125 million to $200 million through 2026.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (h) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.

### ***Obligations under the New Source Review Litigation Consent Decree***

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects. The consent decree has been modified seven times, for various reasons, most recently in 2022. All of the environmental control equipment required by the consent decree has been installed.

### ***Clean Air Act Requirements***

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. Notable developments in significant CAA regulatory requirements affecting AEP’s operations are discussed in the following sections.

### ***National Ambient Air Quality Standards***

The Federal EPA periodically reviews and revises the NAAQS for criteria pollutants under the CAA. Revisions tend to increase the stringency of the standards, which in turn may require AEP to make investments in pollution control equipment at existing generating units, or, since most units are already well controlled, to make changes in how units are dispatched and operated. In January 2023, the Federal EPA announced its proposed decision to strengthen the primary (health-based) annual PM2.5 standard. The Biden administration has previously indicated that it is likely to revisit the NAAQS for ozone, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standard are likely to be finalized or what such changes may be, but will continue to monitor this issue and any future rulemakings.

### ***Regional Haze***

The Federal EPA issued a Clean Air Visibility Rule (CAVR) in 2005, which could require power plants and other facilities to install best available retrofit technology to address regional haze in federal parks and other protected areas. CAVR is implemented by the states, through SIPs, or by the Federal EPA, through FIPs. In 2017, the Federal EPA revised the rules governing submission of SIPs to implement the visibility programs, including a provision that postponed the due date for the next comprehensive SIP revisions until 2021. Petitions for review of the final rule revisions have been filed in the U.S. Court of Appeals for the District of Columbia Circuit.

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Arkansas has an approved regional haze SIP and all of SWEPCo's affected units are in compliance with the relevant requirements.

In Texas, the Federal EPA disapproved portions of the Texas regional haze SIP and finalized a FIP that allows participation in the CSAPR ozone season program to satisfy the NO$_{x}$ regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO$_{2}$ emissions trading program based on CSAPR allowance allocations. Legal challenges to these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.

### ***Cross-State Air Pollution Rule***

CSAPR is a regional trading program designed to address interstate transport of emissions that contribute significantly to non-attainment and maintenance of the 1997 ozone and PM NAAQS in downwind states. CSAPR relies on SO$_{2}$ and NO$_{x}$ allowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted basis.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NO$_{x}$ budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA's NO$_{x}$ regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and oral arguments were held in September 2022. Management cannot predict the outcome of that litigation, but believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced. In addition, in February 2023, the EPA Administrator finalized the denial of 2015 Ozone NAAQS SIPs for 19 states. A FIP that further revises the ozone season NO$_{x}$ budgets under the existing CSAPR program in those states is expected to be finalized in the spring of 2023 and will likely take effect for the 2023 ozone season. Management is evaluating the impacts of the rule changes.

### ***Climate Change, CO$_{2}$ Regulation and Energy Policy***

In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule and remanded it to the Federal EPA. In October 2021, the United States Supreme Court granted certiorari and combined four separate petitions seeking review of the District of Columbia Circuit Court decisions. Oral arguments were held in February 2022 and on June 30, 2022, the United States Supreme Court reversed the District of Columbia Circuit Court's decision and remanded for further proceedings. The Federal EPA must take some action before anything is required of the utilities as a result of this decision. At a minimum, if the Federal EPA intends to implement the ACE rule, it must conduct additional rulemaking to update its applicable deadlines, which have all passed. Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, the scope of which is unknown. The Federal EPA has announced it expects to propose a new rule in 2023. Management is unable to predict how the Federal EPA will respond to the Court's remand.

In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. The Federal EPA has indicated that it intends to conduct a comprehensive review of the existing standards and, if appropriate, amend the emission standards for new fossil fuel-fired generating units. A proposed rule is expected in 2023. Management continues to actively monitor these rulemaking activities.

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While no federal regulatory requirements to reduce CO$_{2}$ emissions are in place, AEP has taken action to reduce and offset CO$_{2}$ emissions from its generating fleet. AEP expects CO$_{2}$ emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative (RGGI), require the retirement of all fossil-fueled generation by 2045 and require 100% renewable energy to be provided to Virginia customers by 2050. Management is taking steps to comply with these requirements, including increasing wind and solar installations, purchasing renewable power and broadening AEP System’s portfolio of energy efficiency programs. In early 2022, Virginia’s governor issued an executive order directing his administration to end Virginia’s participation in RGGI. In December 2022, the Virginia Air Pollution Control Board voted in support of the proposed regulations to withdraw Virginia from RGGI. These regulations have not been finalized. Management will continue to monitor these rulemaking activities.

In October 2022, AEP announced new intermediate and long-term CO$_{2}$ emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. AEP adjusted its near-term carbon dioxide 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. AEP’s total Scope 1 GHG emissions in 2022 were approximately 52.5 million metric tons CO$_{2}$e, approximately a 65% 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 CO$_{2}$ emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.

Excessive costs to comply with future legislation or regulations have led to the announcement of early plant closures 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.

### ***Coal Combustion Residual (CCR) Rule***

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 2020, the Federal EPA revised the CCR rule to include a requirement that unlined CCR storage ponds cease operations and initiate closure by April 11, 2021. The revised rule provides two options that allow facilities to extend the date by which they must cease receipt of coal ash and close the ponds.

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The first option provides an extension to cease receipt of CCR no later than October 15, 2023 for most units, and October 15, 2024 for a narrow subset of units; however, the Federal EPA’s grant of such an extension will be based upon a satisfactory demonstration of the need for additional time to develop alternative ash disposal capacity and will be limited to the soonest timeframe technically feasible to cease receipt of CCR. Additionally, each request must undergo formal review, including public comments, and be approved by the Federal EPA. AEP filed applications for additional time to develop alternative disposal capacity at the following plants:

| Company | Plant Name | Generating Capacity (in MWs) | Net Book Value (a) (in millions) | Projected Retirement Date |
| --- | --- | --- | --- | --- |
| AEGCo | Rockport Plant, Unit 1 | 655 | $226.0 | 2028 |
| APCo | Amos | 2,930 | 2,140.2 | 2040 |
| APCo | Mountaineer | 1,320 | 980.8 | 2040 |
| I&M | Rockport Plant, Unit 1 | 655 | 449.2 (b) | 2028 |
| KPCo | Mitchell Plant | 780 | 576.7 | 2040 |
| SWEPCo | Flint Creek Plant | 258 | 265.4 | 2038 |
| WPCo | Mitchell Plant | 780 | 638.3 | 2040 |

(a) Net book value as of December 31, 2022, before cost of removal including CWIP and inventory.

(b) Amount includes a $147 million regulatory asset related to the retired Tanners Creek Plant. The IURC and MPSC authorized recovery of the Tanners Creek Plant regulatory asset over the useful life of Rockport Plant, Unit 1 in 2015 and 2014, respectively.

In January 2022, the Federal EPA proposed to deny several extension requests filed by the other utilities based on allegations that those utilities are not in compliance with the CCR Rule (the January Actions). In November 2022, the Federal EPA finalized one of these denials. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The January Actions of the Federal EPA have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice and without opportunity for comment. Management is unable to predict the outcome of that litigation.

In July 2022, the Federal EPA proposed conditional approval of the pending extension request for the Mountaineer Plant. The Federal EPA alleged that the Mountaineer Plant was not fully compliant with the CCR Rule. In December 2022, AEP withdrew the pending extension request for the Mountaineer Plant as work to construct new CCR disposal facilities was completed and the extension was no longer needed. The Federal EPA has not yet proposed any action on the other pending extension requests submitted by AEP. However, statements made by the Federal EPA in the context of the proposed and final decisions on extension requests issued to date indicate that there is a risk that the Federal EPA may conclude that AEP is not eligible for an extension of time to cease use of those CCR impoundments for which extension requests are pending and/or that one or more of AEP’s facilities is not in compliance with the CCR Rule. If that occurs, AEP may incur material additional costs to change its plans for complying with the CCR Rule, including the potential to have to temporarily cease operation of one or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the cost of serving customers of the affected utility. Further, actions by the Federal EPA could require AEP to remove coal ash from CCR units that have already been closed in accordance with state law programs or could require AEP to incur costs related to CCR units at various active and legacy facilities.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the Federal EPA’s final CCR rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule, including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash. If additional costs are incurred and AEP is unable to obtain cost recovery, it would reduce future net income and cash flows and impact financial condition. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

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The second option to obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility to continue operating its existing impoundments without developing alternative CCR disposal, provided the facility commits to cease combustion of coal by a date certain. Under this option, a generating facility would have until October 17, 2023 to cease coal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Plant and cease using coal at the Welsh Plant. The table below summarizes the net book value of the Pirkey Plant and Welsh Plant, Units 1 and 3 as of December 31, 2022.

| Company | Plant Name and Unit | Generating Capacity | Net Investment (a) | Accelerated Depreciation Regulatory Asset | Projected Retirement Date |
| --- | --- | --- | --- | --- | --- |
|  |  | (in MWs) | (in millions) |  |  |
| SWEPCo | Pirkey Plant | 580 | $35.1 | $179.5 | 2023 (b) |
| SWEPCo | Welsh Plant, Units 1 & 3 | 1,053 | 416.8 | 85.6 | 2028 (c)(d) |

- (a) Net book value as of December 31, 2022, including CWIP and excluding cost of removal and materials and supplies.
- (b) In January 2023, the LPSC authorized the recovery of SWEPCo's Louisiana share of the Pirkey Plant through a separate rider through 2032. See Note 4 - Rate Matters for additional information. The Pirkey Plant is currently being recovered through 2045 in the Arkansas and Texas jurisdictions.
- (c) In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
- (d) Unit 1 is currently being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is currently being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

To date, the Federal EPA has not taken any action on these pending extension requests. Under the second option above, AEP may need to recover remaining depreciation and estimated closure costs associated with these plants over a shorter period. If AEP cannot ultimately recover the costs of environmental compliance and/or the remaining depreciation and estimated closure costs associated with these plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

### *Clean Water Act Regulations*

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. A revision to the ELG rule, published in October 2020, establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025. Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA's recent actions on facilities' wastewater discharge permitting for FGD wastewater and bottom ash transport water. For affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. AEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. The Federal EPA has announced its intention to reconsider the 2020 rule and to further revise limits applicable to discharges of landfill and impoundment leachate. A proposed rule is expected in 2023. Management cannot predict whether the Federal EPA will actually finalize further revisions or what such revisions might be, but will continue to monitor this issue and will participate in further rulemaking activities as they arise.

In January 2023, the Federal EPA finalized a new rule revising the definition of "waters of the United States," which will become effective in March 2023. The new rule expands the scope of the definition, which means that permits may be necessary where none were previously required and issued permits may need to be reopened to impose additional obligations. Management is evaluating what impacts the revised rule will have on operations.

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In October 2022, the United States Supreme Court heard an appeal related to the scope of “waters of the United States,” specifically which wetlands can be regulated as waters of the United States. Management cannot predict the outcome of that litigation.

### *Impact of Environmental Regulation on Coal-Fired Generation*

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal, remediation and permits. Management continuously evaluates cost estimates of complying with these regulations which may result in a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

Previously, management retired or announced early closure plans for Welsh Plant, Unit 2, Dolet Hills Power Station and Northeastern Plant, Unit 3.

The table below summarizes the net book value, as of December 31, 2022, of generating facilities retired or planned for early retirement in advance of the retirement date currently authorized for ratemaking purposes:

| Company | Plant | Net Investment (a) | Accelerated Depreciation Regulatory Asset | Actual/Projected Retirement Date | Current Authorized Recovery Period | Annual Depreciation (b) |
| --- | --- | --- | --- | --- | --- | --- |
|  |  | (in millions) |  |  |  | (in millions) |
| PSO | Northeastern Plant, Unit 3 | $136.3 | $145.8 | 2026 | (c) | $14.9 |
| SWEPCo | Dolet Hills Power Station | - | 54.8 | 2021 | (d) | - |
| SWEPCo | Pirkey Plant | 35.1 | 179.5 | 2023 | (e) | 11.7 |
| SWEPCo | Welsh Plant, Units 1 and 3 | 416.8 | 85.6 | 2028 (f) | (g) | 37.9 |
| SWEPCo | Welsh Plant, Unit 2 | - | 35.2 | 2016 | (h) | - |

(a) Net book value including CWIP excluding cost of removal and materials and supplies.

(b) These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.

(c) Northeastern Plant, Unit 3 is currently being recovered through 2040.

(d) In January 2023, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station through a separate rider through 2032. In May 2022, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million. In December 2021, the PUCT authorized the recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046 without providing a return on the investment which resulted in a disallowance of $12 million. See Note 4 - Rate Matters for additional information.

(e) In January 2023, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Pirkey Plant through a separate rider through 2032. See Note 4 - Rate Matters for additional information. The Pirkey Plant is currently being recovered through 2045 in the Arkansas and Texas jurisdictions.

(f) In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.

(g) Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

(h) In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.

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## RESULTS OF OPERATIONS

### 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 and their related business activities are outlined below:

#### Vertically Integrated Utilities

- 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.

#### Transmission and Distribution Utilities

- Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
- OPCo purchases energy and capacity at auction to serve standard service offer customers and provides transmission and distribution services for all connected load.

#### AEP Transmission Holdco

- Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROE.
- Development, construction and operation of transmission facilities through investments in AEP's transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROE.

#### Generation & Marketing

- Contracted renewable energy investments and management services.
- Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.
- Competitive generation in PJM.

The remainder of AEP's activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The following discussion of AEP's results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation, as well as Purchased Electricity for Resale, as presented in the Registrants' statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP's financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP's statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP's definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.

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A detailed discussion of AEP’s 2021 results of operations by operating segment can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operation section included in the 2021 Annual Report on Form 10-K filed with the SEC on February 24, 2022.

The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Vertically Integrated Utilities | $1,292.0 | $1,113.6 | $1,061.6 |
| Transmission and Distribution Utilities | 595.7 | 543.4 | 496.4 |
| AEP Transmission Holdco | 673.5 | 677.8 | 504.8 |
| Generation & Marketing | 283.6 | 217.5 | 226.9 |
| Corporate and Other | (537.6) | (64.2) | (89.6) |
| Earnings Attributable to AEP Common Shareholders | $2,307.2 | $2,488.1 | $2,200.1 |

### 2022 Earnings Attributable to AEP Common Shareholders by Segment

![img-0.jpeg](img-0.jpeg)

Note: 2022 Earnings Attributable to AEP Common Shareholders by Segment excludes Corporate and Other which is not considered a reportable segment.

## AEP CONSOLIDATED

### 2022 Compared to 2021

Earnings Attributable to AEP Common Shareholders decreased from $2.5 billion in 2021 to $2.3 billion in 2022.

AEP’s Earnings Attributable to AEP Common Shareholders in 2022 were positively impacted by favorable rate proceedings in various jurisdictions, higher earnings driven by continued transmission investment and increased sales volumes driven by favorable weather and load. In June 2022, AEP also recognized a gain on the sale of mineral rights which contributed to AEP’s Earnings Attributable to AEP Common Shareholders.

The favorable items discussed above were more than offset by a loss on the expected sale of the Kentucky Operations, an impairment of AEP’s equity investment in Flat Ridge 2, increases in interest expense due to higher interest rates and debt balances and a charitable contribution to the AEP Foundation.

AEP’s results of operations by reportable segment are discussed below.

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## VERTICALLY INTEGRATED UTILITIES

![img-1.jpeg](img-1.jpeg)

(a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

| Vertically Integrated Utilities | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Revenues | $11,477.5 | $9,998.5 | $8,879.4 |
| Fuel and Purchased Electricity | 4,007.9 | 3,144.2 | 2,544.9 |
| Gross Margin | 7,469.6 | 6,854.3 | 6,334.5 |
| Other Operation and Maintenance | 3,287.2 | 3,043.1 | 2,754.3 |
| Asset Impairments and Other Related Charges | 24.9 | 11.6 | - |
| Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | (37.0) | - | - |
| Depreciation and Amortization | 2,007.2 | 1,747.6 | 1,600.5 |
| Taxes Other Than Income Taxes | 504.9 | 497.3 | 472.6 |
| Operating Income | 1,682.4 | 1,554.7 | 1,507.1 |
| Other Income | 30.2 | 13.5 | 2.4 |
| Allowance for Equity Funds Used During Construction | 29.5 | 40.2 | 42.2 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 109.8 | 67.9 | 67.9 |
| Interest Expense | (650.9) | (574.2) | (565.0) |
| Income Before Income Tax Benefit and Equity Earnings | 1,201.0 | 1,102.1 | 1,054.6 |
| Income Tax Benefit | (93.8) | (11.2) | (7.0) |
| Equity Earnings of Unconsolidated Subsidiary | 1.4 | 3.4 | 2.9 |
| Net Income | 1,296.2 | 1,116.7 | 1,064.5 |
| Net Income Attributable to Noncontrolling Interests | 4.2 | 3.1 | 2.9 |
| Earnings Attributable to AEP Common Shareholders | $1,292.0 | $1,113.6 | $1,061.6 |

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## Summary of KWh Energy Sales for Vertically Integrated Utilities

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions of KWhs) |  |  |
| Retail: |  |  |  |
| Residential | 32,835 | 32,149 | 31,526 |
| Commercial | 23,770 | 22,833 | 22,225 |
| Industrial | 34,532 | 33,181 | 32,860 |
| Miscellaneous | 2,316 | 2,214 | 2,185 |
| Total Retail | 93,453 | 90,377 | 88,796 |
| Wholesale (a) | 16,099 | 19,025 | 16,987 |
| Total KWhs | 109,552 | 109,402 | 105,783 |

(a) Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.

![img-2.jpeg](img-2.jpeg)

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Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.

### Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in degree days) |  |  |
| Eastern Region |  |  |  |
| Actual - Heating (a) | 2,709 | 2,438 | 2,295 |
| Normal - Heating (b) | 2,717 | 2,720 | 2,727 |
| Actual - Cooling (c) | 1,187 | 1,268 | 1,222 |
| Normal - Cooling (b) | 1,106 | 1,110 | 1,104 |
| Western Region |  |  |  |
| Actual - Heating (a) | 1,523 | 1,241 | 1,160 |
| Normal - Heating (b) | 1,455 | 1,461 | 1,464 |
| Actual - Cooling (c) | 2,695 | 2,370 | 2,117 |
| Normal - Cooling (b) | 2,247 | 2,246 | 2,253 |

- (a) Heating degree days are calculated on a 55 degree temperature base.
- (b) Normal Heating/Cooling represents the thirty-year average of degree days.
- (c) Cooling degree days are calculated on a 65 degree temperature base.

![img-0.jpeg](img-0.jpeg)

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2022 Compared to 2021

# **Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022**  
 **Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities**  
 **(in millions)**

| Year Ended December 31, 2021 | $1,113.6 |
| --- | --- |
| Changes in Gross Margin: |  |
| Retail Margins | 492.6 |
| Margins from Off-system Sales | 9.6 |
| Transmission Revenues | 81.9 |
| Other Revenues | 31.2 |
| Total Change in Gross Margin | 615.3 |
| Changes in Expenses and Other: |  |
| Other Operation and Maintenance | (244.1) |
| Asset Impairments and Other Related Charges | (13.3) |
| Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | 37.0 |
| Depreciation and Amortization | (259.6) |
| Taxes Other Than Income Taxes | (7.6) |
| Other Income | 16.7 |
| Allowance for Equity Funds Used During Construction | (10.7) |
| Non-Service Cost Components of Net Periodic Pension Cost | 41.9 |
| Interest Expense | (76.7) |
| Total Change in Expenses and Other | (516.4) |
| Income Tax Benefit | 82.6 |
| Equity Earnings of Unconsolidated Subsidiary | (2.0) |
| Net Income Attributable to Noncontrolling Interests | (1.1) |
| Year Ended December 31, 2022 | $1,292.0 |

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

- • **Retail Margins** increased \$493 million primarily due to the following:
  - • A \$127 million increase at APCo and WPCo due to an increase in rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
  - • A \$110 million increase at PSO due to a \$61 million increase in base rate revenues and a \$49 million increase in rider revenues. These increases were partially offset in other expense items below.
  - • A \$102 million increase at SWEPCo primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
  - • An \$87 million increase in rider revenues at I&M partially offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
  - • A \$69 million increase in weather-related usage primarily in the residential class.
  - • A \$30 million increase in weather-normalized retail margins primarily in the commercial class.
  - • A \$17 million increase at APCo due to a base rate increase in Virginia implemented in October 2022 following the Virginia Supreme Court remand. This increase was partially offset in Other Operation and Maintenance expense below.

30

These increases were partially offset by:

- A $73 million decrease at PSO and SWEPCo due to the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
- A $6 million decrease in municipal and cooperative revenues at SWEPCo primarily due to the February 2021 severe winter weather event.
- **Margins from Off-system Sales** increased $10 million primarily due to the following:
  - A $32 million increase at I&M primarily due to Rockport Plant, Unit 2 Merchant sales beginning in December 2022 in addition to higher market prices driven by winter storm Elliott.

These increases were partially offset by:

- An $11 million decrease at SWEPCo due to a decrease in Turk Plant merchant sales primarily driven by the February 2021 severe winter weather event.
- A $9 million decrease at KPCo due to a change in the OSS sharing arrangement.
- A $4 million decrease at APCo due to decreased generation.
- **Transmission Revenues** increased $82 million primarily due to the following:
  - A $61 million increase due to continued investment in transmission assets and increased load.
  - A $16 million increase in formula rate true-up activity.
- **Other Revenues** increased $31 million primarily due to the following:
  - A $12 million increase due to pole attachment revenue primarily at APCo. This increase was partially offset in Other Operation and Maintenance Expense below.
  - A $10 million increase due to business development revenue primarily at APCo. This increase was partially offset in Other Operation and Maintenance Expense below.
  - A $4 million increase due to a gain on sale of allowances primarily at I&M. The gain on sale of allowances was partially offset in Retail Margins above.
  - A $4 million increase at I&M due to an increase in barging revenues by River Transportation Division (RTD). The increase in barging revenues was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other and Income Tax Benefit changed between years as follows:

- **Other Operation and Maintenance** expenses increased $244 million primarily due to the following:
  - A $131 million increase in PJM transmission services. This increase was partially offset in Retail Margins above.
  - A $69 million increase in generation expenses primarily due to outages and maintenance at APCo, I&M and PSO.
  - A $40 million increase due to a charitable contribution to the AEP Foundation.
  - A $29 million increase in storm restoration expenses.
  - A $25 million increase in distribution expenses primarily related to vegetation management, pole inspections and distribution overhead costs.
  - A $22 million increase in SPP transmission services. This increase was partially offset in Retail Margins above.
  - A $17 million increase in Energy Efficiency/Demand Response expenses. This increase was offset in Retail Margins above.
  - A $14 million increase in accounts receivable factoring expenses as a result of increased interest rates.

These increases were partially offset by:

- A $132 million decrease due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease was offset in Depreciation and Amortization expense below.
- **Asset Impairments and Other Related Charges** increased $13 million primarily due to:
  - A $25 million increase at APCo due to the write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.

This increase was partially offset by:

- A $12 million decrease due to a partial regulatory disallowance of SWEPCo's investment in the Dolet Hills Power Station as a result of an order received in the 2020 Texas Base Rate Case.

31

- **Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset** increased $37 million at APCo due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting from under-earning during the 2017-2019 Triennial Review.
- **Depreciation and Amortization** expenses increased $260 million primarily due to the following:
  - A $132 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This increase was partially offset in Other Operation and Maintenance expenses above.
  - A $128 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo, the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.
- **Taxes Other Than Income Taxes** increased $8 million primarily due to the following:
  - A $17 million increase at PSO and SWEPCo primarily due to increased property taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in March 2022. This increase was partially offset in Retail Margins above.
  - A $4 million increase at APCo primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.

These increases were partially offset by:

- A $14 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
- **Other Income** increased $17 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at PSO and SWEPCo.
- **Allowance for Equity Funds Used During Construction** decreased $11 million primarily due to a lower AFUDC base at APCo and SWEPCo and a decrease in AFUDC equity rates primarily at APCo and I&M.
- **Non-Service Cost Components of Net Periodic Benefit Cost** decreased $42 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
- **Interest Expense** increased $77 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo, higher interest rates at APCo and increased Advances from Affiliates at PSO and SWEPCo.
- **Income Tax Benefit** increased $83 million primarily due to the following:
  - A $92 million increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property. This increase was partially offset in Retail Margins above.
  - A $16 million increase due to favorable tax return to provision adjustments recorded in the current year.
  - A $15 million increase due to a decrease in flow through depreciation expense.
  - A $7 million increase due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

These increases were partially offset by:

- A $21 million decrease due to an increase in pretax book income.
- A $19 million decrease due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Gross Margin above.

32

# **TRANSMISSION AND DISTRIBUTION UTILITIES**

![img-1.jpeg](img-1.jpeg)

![img-2.jpeg](img-2.jpeg)

(a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

| Transmission and Distribution Utilities | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Revenues | $5,512.0 | $4,492.9 | $4,345.9 |
| Purchased Electricity | 1,287.3 | 729.9 | 682.7 |
| Gross Margin | 4,224.7 | 3,763.0 | 3,663.2 |
| Other Operation and Maintenance | 1,864.2 | 1,573.9 | 1,575.4 |
| Depreciation and Amortization | 746.7 | 690.3 | 751.1 |
| Taxes Other Than Income Taxes | 659.9 | 640.9 | 586.7 |
| Operating Income | 953.9 | 857.9 | 750.0 |
| Other Income | 4.9 | 2.6 | 4.0 |
| Allowance for Equity Funds Used During Construction | 33.6 | 32.3 | 31.9 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 47.6 | 29.0 | 29.4 |
| Interest Expense | (328.0) | (300.9) | (289.2) |
| Income Before Income Tax Expense and Equity Earnings | 712.0 | 620.9 | 526.1 |
| Income Tax Expense | 116.9 | 77.5 | 29.7 |
| Equity Earnings of Unconsolidated Subsidiary | 0.6 | - | - |
| Net Income | 595.7 | 543.4 | 496.4 |
| Net Income Attributable to Noncontrolling Interests | - | - | - |
| Earnings Attributable to AEP Common Shareholders | $595.7 | $543.4 | $496.4 |

33

## Summary of KWh Energy Sales for Transmission and Distribution Utilities

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions of KWhs) |  |  |
| Retail: |  |  |  |
| Residential | 27,479 | 26,830 | 26,518 |
| Commercial | 27,448 | 25,514 | 23,998 |
| Industrial | 25,435 | 23,919 | 22,432 |
| Miscellaneous | 753 | 737 | 749 |
| Total Retail (a) | 81,115 | 77,000 | 73,697 |
| Wholesale (b) | 2,198 | 2,018 | 1,859 |
| Total KWhs | 83,313 | 79,018 | 75,556 |

- (a) Represents energy delivered to distribution customers.
- (b) Primarily Ohio's contractually obligated purchases of OVEC power sold into PJM.

![img-3.jpeg](img-3.jpeg)

34

Heating degree days and cooling degree days are metrics commonly used in the utility industry as a measure of the impact of weather on revenues. In general, degree day changes in the eastern region have a larger effect on revenues than changes in the western region due to the relative size of the two regions and the number of customers within each region.

### Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in degree days) |  |  |
| Eastern Region |  |  |  |
| Actual - Heating (a) | 3,116 | 2,815 | 2,743 |
| Normal - Heating (b) | 3,185 | 3,190 | 3,202 |
| Actual - Cooling (c) | 1,121 | 1,222 | 1,140 |
| Normal - Cooling (b) | 1,011 | 1,016 | 1,006 |
| Western Region |  |  |  |
| Actual - Heating (a) | 450 | 341 | 189 |
| Normal - Heating (b) | 312 | 310 | 313 |
| Actual - Cooling (d) | 2,984 | 2,653 | 2,846 |
| Normal - Cooling (b) | 2,714 | 2,712 | 2,711 |

(a) Heating degree days are calculated on a 55 degree temperature base.

(b) Normal Heating/Cooling represents the thirty-year average of degree days.

(c) Eastern Region cooling degree days are calculated on a 65 degree temperature base.

(d) Western Region cooling degree days are calculated on a 70 degree temperature base.

![img-4.jpeg](img-4.jpeg)

35

2022 Compared to 2021

# **Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022**  
 **Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities**  
 **(in millions)**

| Year Ended December 31, 2021 | $543.4 |
| --- | --- |
| Changes in Gross Margin: |  |
| Retail Margins | 362.3 |
| Margins from Off-system Sales | 61.9 |
| Transmission Revenues | 72.6 |
| Other Revenues | (35.1) |
| Total Change in Gross Margin | 461.7 |
| Changes in Expenses and Other: |  |
| Other Operation and Maintenance | (290.3) |
| Depreciation and Amortization | (56.4) |
| Taxes Other Than Income Taxes | (19.0) |
| Other Income | 2.3 |
| Allowance for Equity Funds Used During Construction | 1.3 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 18.6 |
| Interest Expense | (27.1) |
| Total Change in Expenses and Other | (370.6) |
| Income Tax Expense | (39.4) |
| Equity Earnings of Unconsolidated Subsidiaries | 0.6 |
| Year Ended December 31, 2022 | $595.7 |

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

- • **Retail Margins** increased \$362 million primarily due to the following:
  - • A \$111 million increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.
  - • A \$105 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.
  - • A \$42 million increase due to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
  - • A \$30 million increase due to prior year refunds of Excess ADIT to customers in Texas. This increase was partially offset in Income Tax Expense below.
  - • A \$23 million increase in weather-related usage in Texas primarily due to a 12% increase in cooling degree days and a 32% increase in heating degree days.
  - • A \$19 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
  - • An \$18 million increase in weather-normalized margins primarily in the commercial and industrial classes, partially offset by the residential class.
  - • A \$10 million increase in weather-related usage in Ohio primarily due to the end of decoupling.

36

- • **Margins from Off-system Sales** increased \$62 million primarily due to the following:
  - • A \$52 million increase in off-system sales at OVEC due to higher market prices and volume, partially offset by an increase in PJM expenses driven by winter storm Elliott. This increase was offset in Retail Margins above and Other Revenues below.
  - • A \$10 million increase in deferrals of OVEC costs. This increase was offset in Retail Margins above and Other Revenues below.
- • **Transmission Revenues** increased \$73 million primarily due to the following:
  - • A \$65 million increase due to interim rate increases driven by increased transmission investment.
  - • A \$7 million increase due to prior year refunds to customers in Texas associated with the last base rate case. This increase was offset in Other Revenues below.
- • **Other Revenues** decreased \$35 million primarily due to the following:
  - • A \$38 million decrease in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This decrease was offset in Retail Margins and Margins from Off-system Sales above.
  - • A \$12 million decrease in Texas due to the prior year amortization of a provision for refund recorded associated with the last base rate case. This decrease was offset in Retail Margins and Transmission Revenues above.
  - • A \$7 million decrease in energy efficiency revenues in Texas.These decreases were partially offset by:- • A \$26 million increase in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.

Expenses and Other and Income Tax Expense changed between years as follows:

- • **Other Operation and Maintenance** expenses increased \$290 million primarily due to the following:
  - • An \$87 million increase in transmission expenses in Ohio primarily due to the following:
    - • An \$88 million increase in recoverable PJM expenses. This increase was offset in Retail Margins above.
    - • A \$3 million increase in transmission vegetation management expenses.These increases were partially offset by:- • A \$6 million decrease in transmission formula rate true-up activity.
  - • A \$76 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
  - • A \$21 million increase in bad debt related expenses in Ohio, including \$8 million in 2022 related to Bad Debt Rider over-recovery. This increase was offset in Retail Margins above.
  - • A \$19 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
  - • An \$18 million increase due to a charitable contribution to the AEP Foundation.
  - • A \$17 million increase in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
  - • A \$17 million increase in employee-related expenses.
  - • An \$11 million increase in distribution-related expenses in Texas.
- • **Depreciation and Amortization** expenses increased \$56 million primarily due to the following:
  - • A \$29 million increase due to a higher depreciable base in Texas.
  - • A \$27 million increase in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.
  - • A \$7 million increase in recoverable advanced metering system depreciable expenses in Texas.These increases were partially offset by:- • A \$9 million decrease in recoverable smart grid and Distribution Investment Rider depreciable expenses in Ohio. This decrease was offset in Retail Margins above.

37

- **Taxes Other Than Income Taxes** increased $19 million primarily due to an increase in Ohio in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
- **Non-Service Cost Components of Net Period Benefit Cost** decreased $19 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
- **Interest Expense** increased $27 million primarily due to the following:
  - A $32 million increase in Texas primarily due to higher long-term debt balances and higher interest rates. This increase was partially offset by:
    - A $5 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.
- **Income Tax Expense** increased $39 million primarily due to the following:
  - A $21 million decrease in amortization of Excess ADIT. This decrease was partially offset in Gross Margin above.
  - A $19 million increase due to an increase in pretax book income.
  - A $4 million increase due to a current year change in the accounting policy for the parent company loss benefit.

These increases were partially offset by:

- A $9 million decrease due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.

38

# **AEP TRANSMISSION HOLDCO**

![img-0.jpeg](img-0.jpeg)

![img-1.jpeg](img-1.jpeg)

(a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

| AEP Transmission Holdco | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Transmission Revenues | $1,677.0 | $1,526.2 | $1,198.8 |
| Other Operation and Maintenance | 165.7 | 132.3 | 119.0 |
| Depreciation and Amortization | 355.0 | 306.0 | 257.6 |
| Taxes Other Than Income Taxes | 277.6 | 245.0 | 211.0 |
| Operating Income | 878.7 | 842.9 | 611.2 |
| Interest and Investment Income | 2.0 | 0.7 | 2.9 |
| Allowance for Equity Funds Used During Construction | 70.6 | 67.2 | 74.0 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 5.0 | 2.1 | 2.0 |
| Interest Expense | (169.3) | (146.3) | (133.2) |
| Income Before Income Tax Expense and Equity Earnings | 787.0 | 766.6 | 556.9 |
| Income Tax Expense | 193.6 | 159.6 | 130.8 |
| Equity Earnings of Unconsolidated Subsidiary | 83.4 | 75.0 | 82.4 |
| Net Income | 676.8 | 682.0 | 508.5 |
| Net Income Attributable to Noncontrolling Interests | 3.3 | 4.2 | 3.7 |
| Earnings Attributable to AEP Common Shareholders | $673.5 | $677.8 | $504.8 |

39

# **Summary of Investment in Transmission Assets for AEP Transmission Holdco**

|  | December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Plant in Service | $13,040.2 | $11,718.0 | $10,327.5 |
| Construction Work in Progress | 1,659.9 | 1,495.0 | 1,499.7 |
| Accumulated Depreciation and Amortization | 1,047.6 | 801.8 | 595.7 |
| Total Transmission Property, Net | $13,652.5 | $12,411.2 | $11,231.5 |

![img-2.jpeg](img-2.jpeg)

40

2022 Compared to 2021

# **Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022**
**Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco**
**(in millions)**

| Year Ended December 31, 2021 | $677.8 |
| --- | --- |
| Changes in Transmission Revenues: |  |
| Transmission Revenues | 150.8 |
| Total Change in Transmission Revenues | 150.8 |
| Changes in Expenses and Other: |  |
| Other Operation and Maintenance | (33.4) |
| Depreciation and Amortization | (49.0) |
| Taxes Other Than Income Taxes | (32.6) |
| Interest and Investment Income | 1.3 |
| Allowance for Equity Funds Used During Construction | 3.4 |
| Non-Service Cost Components of Net Periodic Pension Cost | 2.9 |
| Interest Expense | (23.0) |
| Total Change in Expenses and Other | (130.4) |
| Income Tax Expense | (34.0) |
| Equity Earnings of Unconsolidated Subsidiary | 8.4 |
| Net Income Attributable to Noncontrolling Interests | 0.9 |
| Year Ended December 31, 2022 | $673.5 |

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:

- **Transmission Revenues** increased $151 million primarily due to the following:
  - A $180 million increase due to continued investment in transmission assets.
  This increase was partially offset by:
  - A $14 million decrease due to affiliated transmission formula rate true-up activity. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
  - A $5 million decrease due to nonaffiliated transmission formula rate true-up activity.

Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:

- **Other Operation and Maintenance** expenses increased $33 million primarily due to the following:
  - A $12 million increase in employee-related expenses.
  - An $11 million increase due to a charitable contribution to the AEP Foundation.
  - A $5 million increase due to cancelled capital projects.
- **Depreciation and Amortization** expenses increased $49 million primarily due to a higher depreciable base.
- **Taxes Other Than Income Taxes** increased $33 million primarily due to higher property taxes as a result of increased transmission investment.
- **Allowance for Equity Funds Used During Construction** increased $3 million primarily due to higher CWIP.
- **Interest Expense** increased $23 million primarily due to higher long-term debt balances.
- **Income Tax Expense** increased $34 million primarily due to the following:
  - A $21 million increase due to a current year change in the accounting policy for the parent company loss benefit.
  - A $7 million increase due to an increase in pretax book income.
- **Equity Earnings of Unconsolidated Subsidiary** increased $8 million primarily due to higher pretax equity earnings for ETT and PATH-WV, partially offset by lower pretax equity earnings for Pioneer.

41

## GENERATION & MARKETING

![img-3.jpeg](img-3.jpeg)

![img-4.jpeg](img-4.jpeg)

(a) Other AEP Segments excludes Corporate and Other which is not considered a reportable segment.

| Generation & Marketing | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Revenues | $2,466.9 | $2,163.7 | $1,725.6 |
| Fuel, Purchased Electricity and Other | 1,984.3 | 1,806.8 | 1,403.6 |
| Gross Margin | 482.6 | 356.9 | 322.0 |
| Other Operation and Maintenance | 118.7 | 97.5 | 124.9 |
| Gain on Sale of Mineral Rights | (116.3) | - | - |
| Depreciation and Amortization | 93.0 | 80.9 | 72.8 |
| Taxes Other Than Income Taxes | 11.1 | 10.5 | 13.2 |
| Operating Income | 376.1 | 168.0 | 111.1 |
| Interest and Investment Income | 38.9 | 4.2 | 3.2 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 20.6 | 15.4 | 15.4 |
| Interest Expense | (51.8) | (15.6) | (24.0) |
| Income Before Income Tax Benefit and Equity Earnings (Loss) | 383.8 | 172.0 | 105.7 |
| Income Tax Benefit | (83.1) | (48.8) | (108.0) |
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | (192.4) | (10.6) | 3.2 |
| Net Income | 274.5 | 210.2 | 216.9 |
| Net Loss Attributable to Noncontrolling Interests | (9.1) | (7.3) | (10.0) |
| Earnings Attributable to AEP Common Shareholders | $283.6 | $217.5 | $226.9 |

42

## Summary of MWhs Generated for Generation & Marketing

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions of MWhs) |  |  |
| Fuel Type: |  |  |  |
| Coal | 4 | 3 | 4 |
| Renewables | 4 | 4 | 3 |
| Total MWhs | 8 | 7 | 7 |

![img-5.jpeg](img-5.jpeg)

43

2022 Compared to 2021

# **Reconciliation of Year Ended December 31, 2021 to Year Ended December 31, 2022**
**Earnings Attributable to AEP Common Shareholders from Generation & Marketing**
**(in millions)**

| Year Ended December 31, 2021 | $217.5 |
| --- | --- |
| Changes in Gross Margin: |  |
| Merchant Generation | 31.6 |
| Renewable Generation | 38.7 |
| Retail, Trading and Marketing | 55.4 |
| Total Change in Gross Margin | 125.7 |
| Changes in Expenses and Other: |  |
| Other Operation and Maintenance | (21.2) |
| Gain on Sale of Mineral Rights | 116.3 |
| Depreciation and Amortization | (12.1) |
| Taxes Other Than Income Taxes | (0.6) |
| Interest and Investment Income | 34.7 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 5.2 |
| Interest Expense | (36.2) |
| Total Change in Expenses and Other | 86.1 |
| Income Tax Benefit | 34.3 |
| Equity Earnings of Unconsolidated Subsidiaries | (181.8) |
| Net Loss Attributable to Noncontrolling Interests | 1.8 |
| Year Ended December 31, 2022 | $283.6 |

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain cost-of-service for retail operations were as follows:

- **Merchant Generation** increased $32 million primarily due to higher market prices.
- **Renewable Generation** increased $39 million primarily due to higher market prices at Texas wind facilities and new solar projects placed in service.
- **Retail, Trading and Marketing** increased $55 million primarily due to higher retail power and gas margins.

Expenses and Other, Income Tax Benefit and Equity Earnings of Unconsolidated Subsidiaries changed between years as follows:

- **Other Operation and Maintenance** expenses increased $21 million primarily due to the following:
  - A $39 million increase due to the sale of Racine Hydro in 2021.
  - A $14 million increase due to newly placed in service renewable projects in 2022.
  These increases were partially offset by:
  - A $33 million decrease due to higher land sales and sale of renewable development projects in 2022.
- **Gain on Sale of Mineral Rights** increased $116 million due to the current year sale of mineral rights.
- **Depreciation and Amortization** expenses increased $12 million primarily due to a higher depreciable base from increased investments in renewable energy assets.
- **Interest and Investment Income** increased $35 million primarily due to an increase in advances to affiliates and higher interest rates in 2022.
- **Non-Service Cost Components of Net Periodic Benefit Cost** decreased $5 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.

44

- **Interest Expense** increased $36 million primarily due to higher interest rates in 2022.
- **Income Tax Benefit** increased $34 million primarily due to the following:
  - A $22 million increase due to a change in state apportionment impacting deferred state taxes.
  - A $14 million increase due to an unfavorable out of period adjustment recorded in the prior year related to deferred income taxes.
  - A $10 million increase due to a decrease in state taxes.
  - A $7 million increase due to an increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property.

These increases were partially offset by:

- A $10 million decrease due to a current year change in the accounting policy for the parent company loss benefit.
- An $8 million decrease due to an increase in pretax book income.
- **Equity Earnings of Unconsolidated Subsidiaries** decreased $182 million primarily due to the impairment of AEP’s investment in Flat Ridge 2 Wind LLC.

45

# CORPORATE AND OTHER

# *2022 Compared to 2021*

Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $64 million in 2021 to a loss of $538 million in 2022 primarily due to:

- A $363 million pretax loss related to the anticipated sale of Kentucky operations.
- A $128 million increase in interest expense due to higher interest rates on short-term debt, an increase in advances from affiliates and an increase in long-term debt outstanding.
- A $42 million decrease at EIS, primarily due to lower returns on investments and an increase in reserves.
- A $26 million decrease in equity earnings.
- A $24 million decrease due to asset impairments and other related charges.
- An $18 million decrease due to unfavorable changes in gains and losses from AEP’s investment in ChargePoint. As of August 2022, AEP no longer has a direct investment in ChargePoint.

These items were partially offset by:

- A $60 million increase in interest income, primarily due to higher interest income from affiliates.
- A $67 million decrease in Income Tax Expense primarily due to the following:
  - A $66 million decrease due to a loss on the anticipated sale of Kentucky operations.
  - A $40 million decrease due to a current year change in the accounting policy for the parent company loss benefit.
  - A $38 million decrease due to a change in pretax book income.

These items were partially offset by:

- A $79 million increase due to an out of period adjustment related to deferred taxes in 2021.

# AEP SYSTEM INCOME TAXES

# *2022 Compared to 2021*

- **Income Tax Expense** decreased $110 million primarily due to the following:
  - An $88 million increase in tax credits primarily due to an increase in PTCs related to enacted legislation under the IRA and additional capital investment in tax-credit eligible property.
  - A $61 million decrease due to a decrease in pretax book income.
  - A $42 million decrease due to a change in state apportionment and statutory rates related to deferred taxes.
  - A $17 million decrease in state income taxes primarily due to state return to provision adjustments.

These decreases were partially offset by:

- A $55 million increase due to an out of period adjustment recorded in 2021 related to deferred taxes.
- A $41 million decrease in the amortization of Excess ADIT.

46

# FINANCIAL CONDITION

AEP measures financial condition by the strength of its balance sheet and the liquidity provided by its cash flows.

## SIGNIFICANT CASH REQUIREMENTS

AEP’s contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in the footnotes. It is anticipated that these obligations will be satisfied through a combination of cash flows from operations, long-term debt issuances, short-term debt through AEP’s Commercial Paper Program or bank term loans, proceeds from the Kentucky operations sale, proceeds from the sale of competitive contracted renewables and the use of the ATM Program or other equity issuances.

### *Capital Expenditures*

Continued capital investments reflect AEP’s commitment to enhance service and deliver reliable, clean energy and advanced technologies that exceed customer expectations. See “Budgeted Capital Expenditures” herein, for additional information.

### *Long-term Debt*

Long-term debt maturities, including interest, represent a significant cash requirement for AEP and the Registrant Subsidiaries. See Note 14 - Financing Activities for additional information relating to the Registrant Subsidiaries’ long-term debt outstanding as of December 31, 2022, the weighted-average interest rate applicable to each debt category and a schedule of debt maturities over the next five years.

### *Other Significant Cash Requirements*

Operating and finance leases represent a significant component of funding requirements for AEP and the Registrant Subsidiaries. See Note 13 - Leases for additional information.

The AEP System has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. See Note 6 - Commitments, Guarantees and Contingencies for additional information.

As of December 31, 2022, AEP expected to make contributions to the pension plans totaling $6 million in 2023. Based upon the projected benefit obligation and fair value of assets available to pay pension benefits, the pension plans were 101% funded as of December 31, 2022. See “Estimated Future Benefit Payments and Contributions” section of Note 8 for additional information.

Standby letters of credit are entered into with third-parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt security reserves. There is no collateral held in relation to any guarantees in excess of the ownership percentages. In the event any letters of credit are drawn, there is no recourse to third-parties. See “Letters of Credit” section of Note 6 for additional information.

47

## LIQUIDITY AND CAPITAL RESOURCES

### *Debt and Equity Capitalization*

|  | December 31, |  | 2021 |  |
| --- | --- | --- | --- | --- |
|  | 2022 |  | (dollars in millions) |  |
| Long-term Debt, including amounts due within one year (a) | $35,622.6 | 55.8% | $33,454.5 | 57.0% |
| Short-term Debt | 4,112.2 | 6.4 | 2,614.0 | 4.4 |
| Total Debt | 39,734.8 | 62.2 | 36,068.5 | 61.4 |
| AEP Common Equity | 23,893.4 | 37.4 | 22,433.2 | 38.2 |
| Noncontrolling Interests | 229.0 | 0.4 | 247.0 | 0.4 |
| Total Debt and Equity Capitalization | $63,857.2 | 100.0% | $58,748.7 | 100.0% |

(a) Amount excludes $1.2 billion and $1.1 billion of Total Long-term Debt Outstanding classified as Liabilities Held for Sale on the balance sheet as of December 31, 2022 and 2021, respectively. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

AEP’s ratio of debt-to-total capital increased from 61.4% to 62.2% as of December 31, 2021 and 2022, respectively, primarily due to an increase in debt to support distribution, transmission and renewable investment growth in addition to working capital needs due to an increase in deferred fuel costs.

### *Liquidity*

Liquidity, or access to cash, is an important factor in determining AEP’s financial stability. Management believes AEP has adequate liquidity under its existing credit facilities. As of December 31, 2022, AEP had $5 billion in revolving credit facilities to support its commercial paper program. Additional liquidity is available from cash from operations and a receivables securitization agreement. Management is committed to maintaining adequate liquidity. AEP generally uses short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, leasing agreements, hybrid securities or common stock. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. See Note 4 - Rate Matters for additional information. In March 2021, AEP entered into a $500 million 364-day Term Loan and borrowed the full amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. In August 2022, AEP paid off the $500 million Term Loan. In 2022, increased fuel and purchased power prices continue to lead to an increase in under collection of fuel costs. As a result, in July 2022, APCo and KPCo entered into term loans of $100 million and $75 million, respectively, to help address the cash flow implications of the increased fuel and purchased power costs. See “Deferred Fuel Costs” section of Executive Overview for additional information on how the registrants are addressing the increase in deferred fuel regulatory assets. In September 2022, the ODFA issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for $687 million of extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information. In December 2022, AEP entered into four individual Term Loans, including three 364-day Term Loans, totaling $500 million to further address the cash flow implications of increased fuel and purchased power prices. In February 2023, AEP entered into a $500 million term loan to address short-term liquidity needs, made a capital contribution to SWEPCo, totaling $25 million, for general corporate business purposes and made a capital contribution to AEPTCo, totaling $25 million, to manage short-term borrowing capacity under the Money Pool.

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### *Net Available Liquidity*

AEP manages liquidity by maintaining adequate external financing commitments. As of December 31, 2022, available liquidity was approximately $2.6 billion as illustrated in the table below:

|  | Amount (in millions) | Maturity |
| --- | --- | --- |
| Commercial Paper Backup: |  |  |
| Revolving Credit Facility | $4,000.0 | March 2027 (a) |
| Revolving Credit Facility | 1,000.0 | March 2024 (a) |
| Cash and Cash Equivalents | 509.4 |  |
| Total Liquidity Sources | 5,509.4 |  |
| Less: AEP Commercial Paper Outstanding | 2,862.2 |  |
| Net Available Liquidity | $2,647.2 |  |

(a) In April 2022, AEP extended the maturity dates of the Revolving Credit Facilities from March 2026 to March 2027 and from March 2023 to March 2024, respectively.

AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP's utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during 2022 was $2.9 billion. The weighted-average interest rate for AEP's commercial paper during 2022 was 2.74%.

### *Other Credit Facilities*

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling, as of December 31, 2022, $400 million. The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities, as of December 31, 2022, was $287 million with maturities ranging from January 2023 to December 2023.

### *Financing Plan*

As of December 31, 2022, AEP had $2 billion of long-term debt due within one year, excluding $490 million classified as Liabilities Held for Sale on the balance sheet. This also included $250 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current and $210 million of securitization bonds and DCC Fuel notes. Management plans to refinance the majority of the maturities due within one year on a long-term basis.

### *Securitized Accounts Receivables*

AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility was renewed in September 2022 and amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of December 31, 2022, the affiliated utility subsidiaries, with the exception of SWEPCo, were in compliance with all requirements under the agreement. SWEPCo temporarily eased credit policies from August 2022 through October 2022 to assist customers with higher than normal bills driven by increased fuel costs and, in turn, experienced higher than normal aged receivables. In response, in January 2023, AEP Credit amended its receivables securitization agreement to increase the eligibility criteria related to their aged receivables requirements to bring SWEPCo back into compliance.

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### *Debt Covenants and Borrowing Limitations*

AEP’s credit agreements contain certain covenants and require it to maintain a percentage of debt-to-total capitalization at a level that does not exceed 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in AEP’s credit agreements. Debt as defined in the revolving credit agreement excludes securitization bonds and debt of AEP Credit. As of December 31, 2022, this contractually-defined percentage was 59.1%. Non-performance under these covenants could result in an event of default under these credit agreements. In addition, the acceleration of AEP’s payment obligations, or the obligations of certain of AEP’s 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 these credit agreements. This condition also applies in a majority of AEP’s non-exchange-traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable. However, a default under AEP’s non-exchange-traded commodity contracts would not cause an event of default under its credit agreements.

The revolving credit facility does not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders and AEP manages its borrowings to stay within those authorized limits.

### *ATM Program*

AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the year ended December 31, 2022. As of December 31, 2022, approximately $511 million of equity is available for issuance under the ATM offering program. See Note 14 - Financing Activities for additional information.

### *Equity Units*

In August 2020, AEP issued 17 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $850 million. Net proceeds from the issuance were approximately $833 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes due in 2025 and a forward equity purchase contract which settles after three years in August 2023. The proceeds were used to support AEP’s overall capital expenditure plan.

In March 2019, AEP issued 16.1 million Equity Units initially in the form of corporate units, at a stated amount of $50 per unit, for a total stated amount of $805 million. Net proceeds from the issuance were approximately $785 million. Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes due in 2024 and a forward equity purchase contract which settled after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract.

See Note 14 - Financing Activities for additional information.

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## *Dividend Policy and Restrictions*

The Board of Directors declared a quarterly dividend of $0.83 per share in January 2023. Future dividends may vary depending upon AEP’s profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. Management does not believe these restrictions will have any significant impact on its ability to access cash to meet the payment of dividends on its common stock. See “Dividend Restrictions” section of Note 14 for additional information.

## *Credit Ratings*

AEP and its utility subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but its access to the commercial paper market may depend on its credit ratings. In addition, downgrades in AEP’s credit ratings by one of the rating agencies could increase its borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject AEP to additional collateral demands under adequate assurance clauses under its derivative and non-derivative energy contracts.

## **CASH FLOW**

AEP relies primarily on cash flows from operations, debt issuances and its existing cash and cash equivalents to fund its liquidity and investing activities. AEP’s investing and capital requirements are primarily capital expenditures, repaying of long-term debt and paying dividends to shareholders. AEP uses short-term debt, including commercial paper, as a bridge to long-term debt financing. The levels of borrowing may vary significantly due to the timing of long-term debt financings and the impact of fluctuations in cash flows.

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $451.4 | $438.3 | $432.6 |
| Net Cash Flows from Operating Activities | 5,288.0 | 3,839.9 | 3,832.9 |
| Net Cash Flows Used for Investing Activities | (7,751.8) | (6,433.9) | (6,233.9) |
| Net Cash Flows from Financing Activities | 2,568.9 | 2,607.1 | 2,406.7 |
| Net Increase in Cash, Cash Equivalents and Restricted Cash | 105.1 | 13.1 | 5.7 |
| Cash, Cash Equivalents and Restricted Cash at End of Period | $556.5 | $451.4 | $438.3 |

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## Operating Activities

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Net Income | $2,305.6 | $2,488.1 | $2,196.7 |
| Non-Cash Adjustments to Net Income (a) | 3,461.6 | 3,025.9 | 2,954.8 |
| Mark-to-Market of Risk Management Contracts | 15.5 | 112.3 | 66.5 |
| Pension Contributions to Qualified Plan Trust | - | - | (110.3) |
| Property Taxes | (41.2) | (68.0) | (43.3) |
| Deferred Fuel Over/Under Recovery, Net | (319.2) | (1,647.9) | (31.8) |
| Change in Regulatory Assets | (46.7) | (238.9) | (337.9) |
| Change in Other Noncurrent Assets | (187.7) | (126.6) | (151.0) |
| Change in Other Noncurrent Liabilities | 337.8 | 206.4 | (54.5) |
| Change in Certain Components of Working Capital | (237.7) | 88.6 | (656.3) |
| Net Cash Flows from Operating Activities | $5,288.0 | $3,839.9 | $3,832.9 |

(a) Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Lease Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Asset Impairments and Other Related Charges, Impairment of Equity Method Investment, Allowance for Equity Funds Used During Construction, Amortization of Nuclear Fuel, Gain on Sale of Mineral Rights and Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset.

## 2022 Compared to 2021

**Net Cash Flows from Operating Activities** increased by $1.4 billion primarily due to the following:

- A $1.3 billion increase in cash primarily due to the timing of fuel and purchased power revenues and expenses. PSO and SWEPCo were impacted by the February 2021 severe winter weather event in SPP which led to significantly higher fuel and purchased power expenses which were deferred as regulatory assets in 2021. In September 2022, the ODFA issued ratepayer-backed securitization bonds and provided PSO proceeds of $687 million as reimbursement of the extraordinary fuel costs and purchased electricity incurred during the severe winter weather event. See Note 4 - Rate Matters for additional information. In 2022, increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has resulted in an increase in the under collection of fuel costs in most jurisdictions, offsetting the proceeds received by PSO in September 2022. See the “Deferred Fuel Costs” section of Executive Overview for additional information.
- A $253 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
- A $192 million increase in cash from Changes in Regulatory Assets primarily due to incremental other operation and maintenance storm restoration expenses incurred in 2021 by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. The increase due to the February 2021 severe winter weather event was partially offset by the deferral of incremental other operation and maintenance storm restoration expenses incurred in June 2022 by APCo, KPCo, OPCo and WPCo. See Note 4 - Rate Matters for additional information.
- A $131 million increase in cash from Changes in Other Noncurrent Liabilities. The increase is primarily due to changes in provisions for refunds and regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms. See Note 5 - Effects of Regulation for additional information.
- A $97 million increase primarily due to collateral held against risk management contracts due to pricing movement in the commodities market.

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These increases in cash were offset by:

- A $326 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to fuel, material and supplies driven by current year increases in coal inventory and material and supplies in addition to prior year decreases in coal and lignite inventory on hand, an increase in estimated federal income taxes paid and the timing of accounts receivables. These decreases were partially offset by the timing of accounts payable and a return of margin deposits from PJM originally paid in 2021.

### *Investing Activities*

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Construction Expenditures | $(6,671.7) | $(5,659.6) | $(6,246.3) |
| Acquisitions of Nuclear Fuel | (100.7) | (104.5) | (69.7) |
| Acquisition of the Dry Lake Solar Project | - | (114.4) | - |
| Acquisition of the North Central Wind Energy Facilities | (1,207.3) | (652.8) | - |
| Proceeds on Sale of Assets | 218.0 | 118.9 | 71.1 |
| Other | 9.9 | (21.5) | 11.0 |
| Net Cash Flows Used for Investing Activities | $(7,751.8) | $(6,433.9) | $(6,233.9) |

### *2022 Compared to 2021*

**Net Cash Flows Used for Investing Activities** increased by $1.3 billion primarily due to the following:

- A $1 billion increase in construction expenditures, primarily due to increases in Vertically Integrated and Transmission and Distribution segments of $647 million and $411 million, respectively.
- A $440 million increase due to the 2022 acquisition of Traverse, partially offset by the 2021 acquisitions of the Dry Lake Solar Project, Sundance and Maverick. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

These increases in cash used were partially offset by:

- A $99 million increase in Proceeds from Sale of Assets, primarily due to the 2022 sale of certain mineral rights. See Note 7 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.

### *Financing Activities*

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Issuance of Common Stock | $826.5 | $600.5 | $155.0 |
| Issuance/Retirement of Debt, Net | 3,802.5 | 3,631.7 | 3,927.3 |
| Dividends Paid on Common Stock | (1,645.2) | (1,519.5) | (1,424.9) |
| Principal Payments for Finance Lease Obligations | (309.5) | (64.0) | (61.7) |
| Redemption of Noncontrolling Interests | - | - | (100.2) |
| Other | (105.4) | (41.6) | (88.8) |
| Net Cash Flows from Financing Activities | $2,568.9 | $2,607.1 | $2,406.7 |

### *2022 Compared to 2021*

**Net Cash Flows from Financing Activities** decreased by $38 million primarily due to the following:

- A $1.8 billion decrease in issuances of long-term debt. See Note 14 - Financing Activities for additional information.
- A $246 million decrease due to an increase in Principal Payments for Finance Lease Obligations primarily driven by Rockport Plant, Unit 2 final lease payments.
- A $126 million decrease due to an increase in dividends paid on common stock.

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These decreases in cash were partially offset by:

- A $1.4 billion increase in short-term debt primarily due to increased draws under the commercial paper program. See Note 14 - Financing Activities for additional information.
- A $644 million increase due to decreased retirements of long-term debt. See Note 14 - Financing Activities for additional information.
- A $226 million increase in issuances of common stock primarily due to the settlement of the 2019 equity units. See “Equity Units” section of Note 14 for additional information.

The following financing activities occurred during 2022:

AEP Common Stock:

- During 2022, AEP issued 683 thousand shares of common stock under the incentive compensation, employee saving and dividend reinvestment plans. Additionally in 2022, AEP reissued 9 million shares of treasury stock to fulfill share commitments related to AEP’s Equity Units. See “Common Stock” and “Equity Units” section of Note 14 for additional information. AEP received net proceeds of $827 million related to these issuances.

Debt:

- During 2022, AEP issued approximately $4.7 billion of long-term debt, including $3.1 billion of senior unsecured notes at interest rates ranging from 4.5% to 5.95%, $1.3 billion of other debt at various interest rates and $214 million of pollution control bonds at interest rates ranging from 3% to 3.75%. The proceeds from these issuances were primarily used to fund long-term debt maturities, construction programs and to help address working capital needs.
- During 2022, AEP entered into interest rate derivatives with notional amounts totaling $700 million that were designated as cash flow hedges. During 2022, settlements of AEP’s interest rate derivatives resulted in net cash paid of $7 million for derivatives designated as fair hedges. As of December 31, 2022, AEP had a total notional amount of $950 million of outstanding interest rate derivatives designated as fair value hedges and $700 million designated as cash flow hedges.

See “Long-term Debt Subsequent Events” section of Note 14 for Long-term debt and other securities issued, retired and principal payments made after December 31, 2022 through February 23, 2023, the date that the 10-K was issued.

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## BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $6.8 billion of capital expenditures in 2023. For the four year period, 2024 through 2027, management forecasts capital expenditures of $32.9 billion. The expenditures are generally for transmission, generation, distribution, regulated renewables and required environmental investment to comply with the Federal EPA rules. Estimated capital 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 and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of Kentucky operations, proceeds from the sale of competitive contracted renewables and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. The 2023 estimated capital expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

| Segment | 2023 Budgeted Capital Expenditures |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
|  | Environmental | Generation | Renewables | Transmission | Distribution | Other (a) | Total |
| (in millions) |  |  |  |  |  |  |  |
| Vertically Integrated Utilities | $150.7 | $345.5 | $106.1 | $817.3 | $1,310.7 | $426.3 | $3,156.6 (b) |
| Transmission and Distribution Utilities | - | - | - | 999.0 | 993.1 | 287.5 | 2,279.6 |
| AEP Transmission Holdco | - | - | - | 1,290.6 | - | 19.1 | 1,309.7 (b) |
| Generation & Marketing | - | 43.9 | 4.7 | - | - | 21.5 | 70.1 |
| Corporate and Other | - | - | - | - | - | 30.6 | 30.6 |
| Total | $150.7 | $389.4 | $110.8 | $3,106.9 | $2,303.8 | $785.0 | $6,846.6 |

(a) Amount primarily consists of facilities, software and telecommunications.

(b) 2023 budgeted capital expenditures do not include any amounts for KPCo or KTCo.

![img-0.jpeg](img-0.jpeg)

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The table below represents estimated capital investments by business segment for the years 2024 to 2027:

| Segment | 2024 | 2025 | 2026 | 2027 |
| --- | --- | --- | --- | --- |
| Vertically Integrated Utilities (a) | $5,103.6 | $6,417.2 | $3,824.9 | $3,306.3 |
| Transmission and Distribution Utilities | 2,509.8 | 2,280.0 | 2,289.3 | 2,226.5 |
| AEP Transmission Holdco (a) | 1,225.5 | 964.5 | 1,107.1 | 1,246.4 |
| Generation & Marketing | 76.6 | 72.4 | 76.4 | 103.6 |
| Corporate and Other | 27.4 | 14.0 | 15.4 | 2.1 |
| Total | $8,942.9 | $9,748.1 | $7,313.1 | $6,884.9 |

(a) 2024-2027 estimated capital investments do not include any amounts for KPCo or KTCo.

The 2023 estimated capital expenditures by Registrant Subsidiary include distribution, transmission and generation-related investments, as well as expenditures for compliance with environmental regulations as follows:

| Company | 2023 Budgeted Capital Expenditures |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
|  | Environmental | Generation | Renewables | Transmission | Distribution | Other (a) | Total |
| (in millions) |  |  |  |  |  |  |  |
| AEP Texas | $ - | $ - | $ - | $683.3 | $509.1 | $125.6 | $1,318.0 |
| AEPTCo | - | - | - | 1,290.6 | - | 19.1 | 1,309.7 |
| APCo | 65.9 | 122.8 | 25.3 | 324.9 | 432.8 | 146.7 | 1,118.4 |
| I&M | - | 100.8 | 2.0 | 74.6 | 297.1 | 105.5 | 580.0 |
| OPCo | - | - | - | 315.7 | 484.0 | 161.9 | 961.6 |
| PSO | 0.2 | 27.4 | 57.7 | 119.2 | 305.7 | 54.1 | 564.3 |
| SWEPCo | 4.8 | 48.1 | 21.2 | 290.0 | 221.3 | 110.4 | 695.8 |

(a) Amount primarily consists of facilities, software and telecommunications.

![img-1.jpeg](img-1.jpeg)

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# CYBER SECURITY

The electric utility industry is an identified critical infrastructure function with mandatory cyber security requirements under the authority of FERC. The NERC, which FERC certified as the nation's Electric Reliability Organization, developed mandatory critical infrastructure protection cyber security 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 develop 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. 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) is also its NERC Critical Infrastructure Protection Senior Manager, ensuring alignment of compliance with the enterprise-wide security program.

Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks are protected using multiple layers of cyber security controls and authentication. Cyber hackers and other malicious actors have caused material disruption by successfully breaching a number of very secure facilities, including federal agencies and financial institutions. As understanding of these events develop, AEP has adopted a defense in depth approach to cyber security and continually assesses its cyber security 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 has undertaken a variety of actions to monitor and address cyber-related risks. Cyber security and the effectiveness of AEP's cyber security 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 the security leadership team 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 constant 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 cyber security and physical security teams and is responsible for the design, implementation and execution of AEP's security risk management strategy, which includes cyber security. AEP's cyber security team operates a 24/7 Cyber Security Intelligence and Response Center responsible for monitoring the AEP System for cyber risks and threats. The cyber security team constantly scans the AEP System for risks and threats. In addition, under the direction of the CSO, the cyber security 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.

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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. The cyber security team 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, audit services, information technology and operational technology functions critical to the power grid.

The cyber security 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 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.

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# CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

# CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

- It requires assumptions to be made that were uncertain at the time the estimate was made; and
- Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate. However, actual results can differ significantly from those estimates.

The sections that follow present information about critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

# Regulatory Accounting

# Nature of Estimates Required

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

The Registrants recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, the timing of expense and income recognition is matched with regulated revenues. Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

# Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, regulatory assets are recorded on the balance sheets. Management reviews the probability of recovery at each balance sheet date and whenever new events occur. Similarly, regulatory liabilities are recorded when a determination is made that a refund is probable or when ordered by a commission. Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates. If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

# Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income. See Note 5 - Effects of Regulation for additional information related to regulatory assets and regulatory liabilities.

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# Revenue Recognition - Unbilled Revenues

## Nature of Estimates Required

AEP recognizes revenues from customers as the performance obligations of delivering energy to customers are satisfied. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. PSO and SWEPCo do not include the fuel portion in unbilled revenue in accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas.

Accrued unbilled revenues for the Vertically Integrated Utilities segment were $354 million and $246 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Vertically Integrated Utilities segment were $108 million, $(42) million and $40 million for the years ended December 31, 2022, 2021 and 2020, respectively. The changes in unbilled electric revenues are primarily due to changes in weather and rates.

Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $221 million and $172 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Transmission and Distribution Utilities segment were $49 million, $1 million and $5 million for the years ended December 31, 2022, 2021 and 2020, respectively. The changes in unbilled electric revenues are primarily due to changes in weather and rates.

Accrued unbilled revenues for the Generation & Marketing segment were $109 million and $110 million as of December 31, 2022 and 2021, respectively. The changes in unbilled electric utility revenues for AEP’s Generation & Marketing segment were $(1) million, $24 million and $11 million for the years ended December 31, 2022, 2021 and 2020, respectively.

## Assumptions and Approach Used

For each Registrant except AEPTCo, the monthly estimate for unbilled revenues is based upon a primary computation of net generation (generation plus purchases less sales) less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon an allocation of billed KWhs to the current month and previous month, on a billing cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWhs. The two methodologies are evaluated to confirm that they are not statistically different.

For AEP’s Generation & Marketing segment, management calculates unbilled revenues based on a primary computation of load as provided by PJM less the current month’s billed KWhs and estimated line losses, plus the prior month’s unbilled KWhs. However, due to the potential for meter reading issues, meter drift and other anomalies, a secondary computation is made, based upon using the most recent historic daily activity on a per contract basis. The two methodologies are evaluated to confirm that they are not statistically different.

## Effect if Different Assumptions Used

If the two methodologies used to estimate unbilled revenue are statistically different, a limiter adjustment is made to bring the primary computation within one standard deviation of the secondary computation. Additionally, significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the estimate of unbilled revenue.

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## *Accounting for Derivative Instruments*

### *Nature of Estimates Required*

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

### *Assumptions and Approach Used*

The Registrants measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes. If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment. These uncertainties include forward market price assumptions.

The Registrants reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction's probability of occurrence within the specified time period as provided in the original hedge documentation.

### *Effect if Different Assumptions Used*

There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into Operating Income.

For additional information see Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements. See 'Fair Value Measurements of Assets and Liabilities' section of Note 1 for AEP's fair value calculation policy.

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# Long-Lived Assets

## Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance and “Regulated Operations” accounting guidance, the Registrants evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable. Such events or changes in circumstance include planned abandonments, probable disallowances for rate-making purposes of assets determined to be recently completed plant and assets that meet the held-for-sale criteria. The Registrants utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.

An impairment evaluation of a long-lived, held and used asset may result from an abandonment, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses. If the book value of the asset is not recoverable through estimated, future undiscounted cash flows, the Registrants record an impairment to the extent that the fair value of the asset is less than its book value. Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the non-discounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset. Assets held for sale must be measured at the lower of the book value or fair value less cost to sell. An impairment is recognized if an asset’s fair value less costs to sell is less than its book value. Any impairment charge is recorded as a reduction to earnings.

## Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the Registrants estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. Cash flow estimates are based on relevant information available at the time the estimates are made. Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date. Such characteristics include, for example, the condition and location of the asset or restrictions on the use of the asset. The Registrants perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for regulated assets. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

## Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions are used in the applied valuation techniques. Estimates for depreciation rates contemplate the history of interim capital replacements and the amount of salvage expected. In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time. Differences in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, the timing and terms of the transactions and management’s analysis of the benefits of the transaction.

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## *Pension and OPEB*

AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, non-qualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans). AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Pension Plans and OPEB plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1. See Note 8 - Benefit Plans for information regarding costs and assumptions for the Plans.

The following table shows the net periodic cost (credit) of the Plans:

| Net Periodic Cost (Credit) | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Pension Plans | $80.9 | $138.2 | $108.6 |
| OPEB | (144.8) | (122.0) | (109.7) |

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets. In developing the expected long-term rate of return assumption for 2023, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Management also considered historical returns of the investment markets and tax rates which affect a portion of the OPEB plans’ assets. Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7.5% for the Qualified Plan and 7.25% for the OPEB plans.

The expected long-term rate of return on the Plans’ assets is based on management’s targeted asset allocation and expected investment returns for each investment category. Assumptions for the Plans are summarized in the following table:

|  | Pension Plans |  | OPEB |  |
| --- | --- | --- | --- | --- |
|  | 2023 Target Asset Allocation | Assumed/ Expected Long-Term Rate of Return | 2023 Target Asset Allocation | Assumed/ Expected Long-Term Rate of Return |
| Equity | 30% | 9.28% | 59% | 8.30% |
| Fixed Income | 54 | 5.92 | 40 | 5.71 |
| Other Investments | 15 | 9.06 | - | - |
| Cash and Cash Equivalents | 1 | 2.67 | 1 | 2.67 |
| Total | 100% |  | 100% |  |

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Management believes that 7.5% for the Qualified Plan and 7.25% for the OPEB plans are reasonable estimates of the long-term rate of return on the Plans’ assets. The Pension Plans’ assets had an actual loss of 16.88% and a gain of 5.41% for the years ended December 31, 2022 and 2021, respectively. The OPEB plans’ assets had an actual loss of 19.53% and a gain of 8.67% for the years ended December 31, 2022 and 2021, respectively. Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

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AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2022, AEP had cumulative gains of approximately $523 million for the Qualified Plan that remain to be recognized in the calculation of the market-related value of assets. These unrecognized market-related net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation - Retirement Benefits” accounting guidance.

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate as of December 31, 2022 under this method was 5.5% for the Qualified Plan, 5.6% for the Nonqualified Plans and 5.5% for the OPEB plans. Due to the effect of the unrecognized net actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.5%, discount rates of 5.5% and 5.6% and various other assumptions, management estimates credits for the Pension Plans will approximate $24 million and $20 million in 2023 and 2024, respectively. Management estimates that the pension costs for the Pension Plans will approximate $8 million in 2025. Based on an expected rate of return on the OPEB plans’ assets of 7.25%, a discount rate of 5.5% and various other assumptions, management estimates OPEB plan credits will approximate $107 million, $65 million and $62 million in 2023, 2024 and 2025, respectively. Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

The value of AEP’s Pension Plans’ assets decreased to $4.1 billion as of December 31, 2022 from $5.4 billion as of December 31, 2021 primarily due to negative investment returns. During 2022, the Qualified Plan paid $395 million and the Nonqualified Plans paid $7 million in benefits to plan participants. The value of AEP’s OPEB plans’ assets decreased to $1.5 billion as of December 31, 2022 from $2.0 billion as of December 31, 2021 primarily due to negative investment returns. During 2022, the OPEB plans paid $140 million in benefits to plan participants.

#### *Nature of Estimates Required*

AEP sponsors pension and OPEB plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance. The measurement of pension and OPEB obligations, costs and liabilities is dependent on a variety of assumptions.

#### *Assumptions and Approach Used*

The critical assumptions used in developing the required estimates include the following key factors:

- Discount rate
- Compensation increase rate
- Cash balance crediting rate
- Health care cost trend rate
- Expected return on plan assets

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Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

#### *Effect if Different Assumptions Used*

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. These differences may result in a significant impact to the amount of pension and OPEB expense recorded. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

|  | Pension Plans |  | OPEB |  |
| --- | --- | --- | --- | --- |
|  | +0.5% | -0.5% | +0.5% | -0.5% |
| (in millions) |  |  |  |  |
| Effect on December 31, 2022 Benefit Obligations |  |  |  |  |
| Discount Rate | $(170.2) | $184.9 | $(37.1) | $40.3 |
| Compensation Increase Rate | 19.7 | (18.3) | NA | NA |
| Cash Balance Crediting Rate | 57.2 | (54.2) | NA | NA |
| Health Care Cost Trend Rate | NA | NA | 6.1 | (5.4) |
| Effect on 2022 Periodic Cost |  |  |  |  |
| Discount Rate | $(12.7) | $14.0 | $3.0 | $(2.9) |
| Compensation Increase Rate | 7.4 | (6.8) | NA | NA |
| Cash Balance Crediting Rate | 14.3 | (13.4) | NA | NA |
| Health Care Cost Trend Rate | NA | NA | 0.6 | (0.2) |
| Expected Return on Plan Assets | (24.1) | 24.1 | (10.1) | 10.1 |

NA Not applicable.

#### **SIGNIFICANT TAX LEGISLATION**

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. The IRS has since released interim guidance in the form of Notices addressing the Prevailing Wage and Apprenticeship Requirements tied to full value PTCs and ITCs for projects that begin construction on or after January 29, 2023, and time-sensitive issues related to the CAMT. As further significant guidance from Treasury and the IRS is expected on the tax provisions in the IRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, cash flows and financial condition.

The enactment of the IRA will have future cash flow and income tax reporting considerations. AEP and subsidiaries expect to be applicable CAMT corporations beginning in 2023 and AEP expects to have CAMT cash tax payments beginning in 2024. CAMT cash taxes are expected to be offset by regulatory recovery, the utilization of tax credits and additionally, the cash inflow generated by the sale of tax credits. The sale of tax credits will be presented in the operating section of the cash flow statement consistent with the presentation of cash taxes paid. AEP will present the gain or loss on sale of tax credits through income tax expense on the statement of income. Management believes this presentation provides consistency in financial statement reporting as it matches the originating income tax benefit of the tax credit.

#### **ACCOUNTING STANDARDS**

See Note 2 - New Accounting Standards for information related to accounting standards. There are no new standards expected to have a material impact to the Registrants' financial statements.

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# QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## *Market Risks*

The Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through transactions in power, coal, natural gas and marketing contracts. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates.

The Transmission and Distribution Utilities segment is exposed to energy procurement risk and interest rate risk.

The Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risks which may be subject to capacity risk, credit risk as well as interest rate risk. These risks represent the risk of loss that may impact this segment due to changes in the underlying market prices or rates. In addition, the Generation & Marketing segment is also exposed to certain market risks as a power producer and through transactions in wholesale electricity, natural gas and marketing contracts.

Management employs risk management contracts including physical forward and financial forward purchase-and-sale contracts. Management engages in risk management of power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. As a result, AEP is subject to price risk. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Regulated Risk Committee and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Financial Officer, Chief Commercial Officer, Executive Vice President Utilities, Senior Vice President of Regulated Commercial Operations, Senior Vice President of Grid Solutions, Senior Vice President of Treasury and Risk and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC's Chief Financial Officer, Chief Commercial Officer, Senior Vice President of Treasury and Risk, Senior Vice President of Competitive Commercial Operations and Chief Risk Officer. When commercial activities exceed predetermined limits, positions are modified to reduce the risk to be within the limits unless specifically approved by the respective committee.

Due to multiple defaults of market participants, ERCOT had a large outstanding unpaid balance associated with the February 2021 winter storm. A certain portion of this balance has been securitized and disbursed to impacted market participants. A recovery plan has been reached by ERCOT for the remaining portion of the outstanding balance. In both cases, financial costs are allocated to certain market participants and in the role AEPEP is exposed, but not materially. If the market rules were to change on how socialized losses are allocated this could affect AEPEP's exposure. Regardless of the approach of how socialized losses are allocated there are potential downstream impacts that could push counterparties into financial distress and or bankruptcy, affecting AEPEP, AEP Texas and ETT.

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The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2021:

# **MTM Risk Management Contract Net Assets (Liabilities)**
**Year Ended December 31, 2022**

|  | Vertically Integrated Utilities | Transmission and Distribution Utilities | Generation & Marketing | Total |
| --- | --- | --- | --- | --- |
|  | (in millions) |  |  |  |
| Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021 | $59.8 | $(91.4) | $275.9 | $244.3 |
| (Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | (75.5) | 5.7 | (66.0) | (135.8) |
| Fair Value of New Contracts at Inception When Entered During the Period (a) | - | - | 0.9 | 0.9 |
| Changes in Fair Value Due to Market Fluctuations During the Period (b) | 10.7 | - | 149.7 | 160.4 |
| Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 133.7 | 45.7 | - | 179.4 |
| MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d) | (2.5) | - | - | (2.5) |
| Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2022 | $126.2 | $(40.0) | $360.5 | 446.7 |
| Commodity Cash Flow Hedge Contracts |  |  |  | 283.3 |
| Interest Rate Cash Flow Hedge Contracts |  |  |  | 11.0 |
| Fair Value Hedge Contracts |  |  |  | (127.4) |
| Collateral Deposits |  |  |  | (479.6) |
| Total MTM Derivative Contract Net Assets as of December 31, 2022 |  |  |  | $134.0 |

- (a) Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
- (b) Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
- (c) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable on the balance sheet.
- (d) MTM risk management contract net assets relating to KPCo are classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 7 for additional information.

See Note 10 - Derivatives and Hedging and Note 11 - Fair Value Measurements for additional information related to risk management contracts. The following tables and discussion provide information on credit risk and market volatility risk.

# **Credit Risk**

Credit risk is mitigated in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEP has risk management contracts (includes non-derivative contracts) with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. As of December 31, 2022, credit exposure net of collateral to sub investment grade counterparties was approximately 0.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).

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As of December 31, 2022, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

| Counterparty Credit Quality | Exposure Before Credit Collateral | Credit Collateral | Net Exposure | Number of Counterparties >10% of Net Exposure | Net Exposure of Counterparties >10% |
| --- | --- | --- | --- | --- | --- |
|  | (in millions, except number of counterparties) |  |  |  |  |
| Investment Grade | $691.0 | $236.7 | $454.3 | 2 | $131.2 |
| Split Rating | 9.0 | - | 9.0 | 1 | 9.0 |
| Noninvestment Grade | 2.3 | 2.2 | 0.1 | 1 | 0.1 |
| No External Ratings: |  |  |  |  |  |
| Internal Investment Grade | 41.2 | - | 41.2 | 2 | 24.8 |
| Internal Noninvestment Grade | 5.2 | 2.5 | 2.7 | 3 | 2.5 |
| Total as of December 31, 2022 | $748.7 | $241.4 | $507.3 |  |  |

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.

#### *Value at Risk (VaR) Associated with Risk Management Contracts*

Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of December 31, 2022, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.

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The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:

# **VaR Model  
Trading Portfolio**

| Twelve Months Ended December 31, 2022 |  |  |  | Twelve Months Ended December 31, 2021 |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
| End | High | Average | Low | End | High | Average | Low |
| (in millions) |  |  |  | (in millions) |  |  |  |
| $0.5 | $4.5 | $0.7 | $0.1 | $0.4 | $3.6 | $0.4 | $0.1 |

# **VaR Model  
Non-Trading Portfolio**

| Twelve Months Ended December 31, 2022 |  |  |  | Twelve Months Ended December 31, 2021 |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
| End | High | Average | Low | End | High | Average | Low |
| (in millions) |  |  |  | (in millions) |  |  |  |
| $17.7 | $76.9 | $24.7 | $6.7 | $8.3 | $14.9 | $3.7 | $0.7 |

Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.

# ***Interest Rate Risk***

AEP is exposed to interest rate market fluctuations in the normal course of business operations. Prior to 2022, interest rates remained at low levels and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. However, during 2022, the Federal Reserve approved rate increases totaling 4.25%. The Federal Reserve has indicated that, in light of continued signs of inflation, it foresees further increases in interest rates in 2023. AEP has outstanding short and long-term debt which is subject to variable rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the twelve months ended December 31, 2022, 2021 and 2020, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $47 million, $33 million and $32 million, respectively.

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# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

## *Opinions on the Financial Statements and Internal Control over Financial Reporting*

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021 and the related consolidated statements of income, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in *Internal Control - Integrated Framework* (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in *Internal Control - Integrated Framework* (2013) issued by the COSO.

## *Basis for Opinions*

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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## *Definition and Limitations of Internal Control over Financial Reporting*

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

## *Critical Audit Matters*

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

## *Accounting for the Effects of Cost-Based Regulation*

As described in Notes 1 and 5 to the consolidated financial statements, the Company's consolidated financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. As of December 31, 2022, there were $5.6 billion of deferred costs included in regulatory assets, $0.8 billion of which were pending final regulatory approval, and $8.0 billion of regulatory liabilities awaiting potential refund or future rate reduction, $0.2 billion of which were pending final regulatory determination. Regulatory assets (deferred expenses) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and matching income with its passage to customers in cost-based regulated rates. Management reviews the probability of recovery of regulatory assets and refund of regulatory liabilities at each balance sheet date and whenever new events occur, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation.

The principal considerations for our determination that performing procedures relating to the accounting for the effects of cost-based regulation is a critical audit matter are the significant judgment by management in the ongoing evaluation of the recovery of regulatory assets and refund of regulatory liabilities, and in applying guidance contained in rate orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability of recovery of regulatory assets and refund of regulatory liabilities.

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's evaluation of new events, such as changes in the regulatory environment, issuance of regulatory commission orders, or passage of new legislation, including the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, evaluating the reasonableness of management's assessment of probability of future recovery for regulatory assets and refund of regulatory liabilities. Testing of regulatory assets and liabilities, involved evaluating the provisions and formulas outlined in rate orders, other regulatory correspondence, application of relevant regulatory precedents, and other relevant evidence.

### *Valuation of Level 3 Risk Management Commodity Contracts*

As described in Notes 1, 10 and 11 to the consolidated financial statements, the Company employs risk management commodity contracts including physical and financial forward purchase and sale contracts and, to a lesser extent, over-the-counter swaps and options to accomplish its risk management strategies. Certain over-the-counter and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. As disclosed by management, the fair value of these risk management commodity contracts is estimated based on the best market information available, including valuation models that estimate future energy prices based on existing market and broker quotes, and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment including forward market price assumptions. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. Management utilized such unobservable pricing inputs to value its Level 3 risk management commodity contract assets and liabilities, which totaled $332.5 million and $180.6 million, as of December 31, 2022, respectively.

The principal considerations for our determination that performing procedures relating to the valuation of Level 3 risk management commodity contracts is a critical audit matter are the significant judgment by management when developing the fair value of the commodity contracts; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence relating to the forward market price assumptions used in management's valuation models. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's valuation of the risk management commodity contracts, including controls over the assumptions used to value the Level 3 risk management commodity contracts. These procedures also included, among others, testing management's process for developing the fair value of the Level 3 risk management commodity contracts, evaluating the appropriateness of the valuation models, evaluating the reasonableness of the forward market price assumptions, and testing the data used by management in the valuation models. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the forward market price assumptions.

### *Classification of the Assets and Liabilities of KPCo and KTCo as Held for Sale*

As described in Note 7 to the consolidated financial statements, in October 2021 the Company entered into a Stock Purchase Agreement (SPA) to sell Kentucky Power Company (KPCo) and Kentucky Transmission Company (KTCo) to Liberty Utilities Co. (Liberty) for $2.85 billion. In September 2022, the Company and Liberty entered into an amendment to the SPA which reduced the purchase price to approximately $2.646 billion. The sale is subject to several regulatory approvals, including approval from the Kentucky Public Service Commission (KPSC) and from the Federal Energy Regulatory Commission (FERC). In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale. In December 2022, the FERC issued an order denying, without prejudice, authorization of the proposed sale stating the applicants failed to demonstrate the proposed transaction will not have adverse effect on rates. In January 2023, the Company and Liberty entered into

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an amendment to the SPA that specified the applicants will submit a new filing for approval under Section 203 of the Federal Power Act. The new filing was submitted to the FERC on February 14, 2023. Management believes it is probable that FERC authorization under Section 203 of the Federal Power Act will be received and closing will occur in 2023. Therefore, the assets and liabilities of KPCO and KTCo will continue to be classified as held for sale as of December 31, 2022.

The principal considerations for our determination that performing procedures relating to the classification of the assets and liabilities of KPCo and KTCo is a critical audit matter are the significant judgment by management in determining the classification of the assets and liabilities as held for sale, and in assessing the impact of regulatory orders and other relevant evidence; this in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the probability that a sale of the assets and liabilities of KPCO and KTCo will occur resulting in held for sale classification as of December 31, 2022.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's determination of the classification of the assets and liabilities of KPCo and KTCo as held for sale. These procedures also included, among others, evaluating management's determination of the classification of KPCo and KTCo as held for sale which involved i) evaluating the reasonableness of management's assessment of probability of the sale to occur resulting in held for sale classification as of the balance sheet date ii) evaluating the commitment of both parties to the sale as supported by public statements and other representations, iii) evaluating guidance in applicable regulatory orders and other regulatory correspondence, iv) consideration of relevant regulatory and legal precedents, and v) reviewing written agreements in place between the parties related to the sale.

/s/ PricewaterhouseCoopers LLP

Columbus, Ohio February 23, 2023

We have served as the Company's auditor since 2017.

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# MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and Subsidiary Companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEP's internal control is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP's internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on management's assessment, management concluded AEP's internal control over financial reporting was effective as of December 31, 2022.

PricewaterhouseCoopers LLP, AEP's independent registered public accounting firm has issued an audit report on the effectiveness of AEP's internal control over financial reporting as of December 31, 2022. The Report of Independent Registered Public Accounting Firm appears on the previous page.

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**  
 **CONSOLIDATED STATEMENTS OF INCOME**  
 **For the Years Ended December 31, 2022, 2021 and 2020**  
 **(in millions, except per-share and share amounts)**

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| REVENUES |  |  |  |
| Vertically Integrated Utilities | $11,292.8 | $9,852.2 | $8,753.2 |
| Transmission and Distribution Utilities | 5,489.6 | 4,464.1 | 4,238.7 |
| Generation & Marketing | 2,448.9 | 2,108.3 | 1,621.0 |
| Other Revenues | 408.2 | 367.4 | 305.6 |
| TOTAL REVENUES | 19,639.5 | 16,792.0 | 14,918.5 |
| EXPENSES |  |  |  |
| Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | 7,097.9 | 5,466.3 | 4,369.7 |
| Other Operation | 2,878.1 | 2,547.7 | 2,572.4 |
| Maintenance | 1,249.4 | 1,121.8 | 1,010.4 |
| Loss on the Expected Sale of the Kentucky Operations | 363.3 | - | - |
| Asset Impairments and Other Related Charges | 48.8 | 11.6 | - |
| Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | (37.0) | - | - |
| Gain on Sale of Mineral Rights | (116.3) | - | - |
| Depreciation and Amortization | 3,202.8 | 2,825.7 | 2,682.8 |
| Taxes Other Than Income Taxes | 1,469.8 | 1,407.6 | 1,295.5 |
| TOTAL EXPENSES | 16,156.8 | 13,380.7 | 11,930.8 |
| OPERATING INCOME | 3,482.7 | 3,411.3 | 2,987.7 |
| Other Income (Expense): |  |  |  |
| Other Income | 11.6 | 41.4 | 57.0 |
| Allowance for Equity Funds Used During Construction | 133.7 | 139.7 | 148.1 |
| Non-Service Cost Components of Net Periodic Benefit Cost | 188.5 | 118.6 | 119.0 |
| Interest Expense | (1,396.1) | (1,199.1) | (1,165.7) |
| INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS (LOSS) | 2,420.4 | 2,511.9 | 2,146.1 |
| Income Tax Expense | 5.4 | 115.5 | 40.5 |
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | (109.4) | 91.7 | 91.1 |
| NET INCOME | 2,305.6 | 2,488.1 | 2,196.7 |
| Net Income (Loss) Attributable to Noncontrolling Interests | (1.6) | - | (3.4) |
| EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $2,307.2 | $2,488.1 | $2,200.1 |
| WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | 511,841,946 | 500,522,177 | 495,718,223 |
| TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $4.51 | $4.97 | $4.44 |
| WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | 513,484,609 | 501,784,032 | 497,226,867 |
| TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $4.49 | $4.96 | $4.42 |

See Notes to Financial Statements of Registrants beginning on page 81.

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**  
 **CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)**  
 **For the Years Ended December 31, 2022, 2021 and 2020**  
 **(in millions)**

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| Net Income | $2,305.6 | $2,488.1 | $2,196.7 |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES |  |  |  |
| Cash Flow Hedges, Net of Tax of $21.6, $66.6 and $1.8 in 2022, 2021 and 2020, Respectively | 81.4 | 250.5 | 6.9 |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(2.8), $(2.2) and $(1.9) in 2022, 2021 and 2020, Respectively | (10.4) | (8.1) | (7.0) |
| Pension and OPEB Funded Status, Net of Tax of $(41.3), $7.3 and $16.7 in 2022, 2021 and 2020, Respectively | (155.4) | 27.5 | 62.7 |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets, Net of Tax of $(4.4), $0 and $0 in 2022, 2021 and 2020, Respectively | (16.7) | - | - |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (101.1) | 269.9 | 62.6 |
| TOTAL COMPREHENSIVE INCOME | 2,204.5 | 2,758.0 | 2,259.3 |
| Total Comprehensive Loss Attributable To Noncontrolling Interests | (1.6) | - | (3.4) |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $2,206.1 | $2,758.0 | $2,262.7 |

*See Notes to Financial Statements of Registrants beginning on page 81.*

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**
**CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY**
**For the Years Ended December 31, 2022, 2021 and 2020**
**(in millions)**

|  | AEP Common Shareholders |  |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- | --- |
|  | Common Stock |  | Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total |
|  | Shares | Amount |  |  |  |  |  |
| TOTAL EQUITY - DECEMBER 31, 2019 | 514.4 | $3,343.4 | $6,535.6 | $9,900.9 | $(147.7) | $281.0 | $19,913.2 |
| Issuance of Common Stock | 2.4 | 15.9 | 139.1 |  |  |  | 155.0 |
| Common Stock Dividends |  |  |  | (1,415.0) (a) |  | (9.9) | (1,424.9) |
| Other Changes in Equity |  |  | (85.8) (b) |  |  | (0.4) | (86.2) |
| ASU 2016-13 Adoption |  |  |  | 1.8 |  |  | 1.8 |
| Acquisition of Incremental Interest in Santa Rita East |  |  |  |  |  | (43.7) | (43.7) |
| Net Income (Loss) |  |  |  | 2,200.1 |  | (3.4) | 2,196.7 |
| Other Comprehensive Income |  |  |  |  | 62.6 |  | 62.6 |
| TOTAL EQUITY - DECEMBER 31, 2020 | 516.8 | 3,359.3 | 6,588.9 | 10,687.8 | (85.1) | 223.6 | 20,774.5 |
| Issuance of Common Stock | 7.6 | 49.4 | 551.1 |  |  |  | 600.5 |
| Common Stock Dividends |  |  |  | (1,507.7) (a) |  | (11.8) | (1,519.5) |
| Other Changes in Equity |  |  | 32.6 | (1.1) |  | 16.3 | 47.8 |
| Acquisition of Dry Lake Solar Project |  |  |  |  |  | 18.9 | 18.9 |
| Net Income |  |  |  | 2,488.1 |  | - | 2,488.1 |
| Other Comprehensive Income |  |  |  |  | 269.9 |  | 269.9 |
| TOTAL EQUITY - DECEMBER 31, 2021 | 524.4 | 3,408.7 | 7,172.6 | 11,667.1 | 184.8 | 247.0 | 22,680.2 |
| Issuance of Common Stock | 0.7 | 4.4 | 822.1 |  |  |  | 826.5 |
| Common Stock Dividends |  |  |  | (1,628.7) (a) |  | (16.5) | (1,645.2) |
| Other Changes in Equity |  |  | 56.3 |  |  | 0.1 | 56.4 |
| Net Income (Loss) |  |  |  | 2,307.2 |  | (1.6) | 2,305.6 |
| Other Comprehensive Loss |  |  |  |  | (101.1) |  | (101.1) |
| TOTAL EQUITY - DECEMBER 31, 2022 | 525.1 | $3,413.1 | $8,051.0 | $12,345.6 | $83.7 | $229.0 | $24,122.4 |

(a) Cash dividends declared per AEP common share were $3.17, $3.00 and $2.84 for the years ended December 31, 2022, 2021 and 2020, respectively.
(b) Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units. See “Equity Units” section of Note 14 for additional information.

See Notes to Financial Statements of Registrants beginning on page 81.

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**  
 **CONSOLIDATED BALANCE SHEETS**  
 **ASSETS**  
 **December 31, 2022 and 2021**  
 **(in millions)**

|  | December 31, |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| CURRENT ASSETS |  |  |
| Cash and Cash Equivalents | $509.4 | $403.4 |
| Restricted Cash (December 31, 2022 and 2021 Amounts Include $47.1 and $48, Respectively, Related to Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Santa Rita East) | 47.1 | 48.0 |
| Other Temporary Investments (December 31, 2022 and 2021 Amounts Include $182.9 and $214.8, Respectively, Related to EIS and Transource Energy) | 187.5 | 220.4 |
| Accounts Receivable: |  |  |
| Customers | 1,081.5 | 720.9 |
| Accrued Unbilled Revenues | 287.9 | 204.4 |
| Pledged Accounts Receivable - AEP Credit | 1,207.4 | 1,038.0 |
| Miscellaneous | 49.6 | 33.9 |
| Allowance for Uncollectible Accounts | (56.1) | (55.6) |
| Total Accounts Receivable | 2,570.3 | 1,941.6 |
| Fuel | 413.2 | 307.9 |
| Materials and Supplies | 888.9 | 681.3 |
| Risk Management Assets | 340.4 | 194.4 |
| Accrued Tax Benefits | 99.4 | 121.5 |
| Regulatory Asset for Under-Recovered Fuel Costs | 1,286.8 | 647.8 |
| Margin Deposits | 81.9 | 193.4 |
| Assets Held for Sale | 2,823.5 | 2,919.7 |
| Prepayments and Other Current Assets | 170.3 | 129.8 |
| TOTAL CURRENT ASSETS | 9,418.7 | 7,809.2 |
| PROPERTY, PLANT AND EQUIPMENT |  |  |
| Electric: |  |  |
| Generation | 24,597.7 | 23,088.1 |
| Transmission | 32,312.9 | 29,911.1 |
| Distribution | 26,077.2 | 24,440.0 |
| Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | 6,142.1 | 5,682.9 |
| Construction Work in Progress | 4,664.1 | 3,684.3 |
| Total Property, Plant and Equipment | 93,794.0 | 86,806.4 |
| Accumulated Depreciation and Amortization | 22,511.1 | 20,805.1 |
| TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 71,282.9 | 66,001.3 |
| OTHER NONCURRENT ASSETS |  |  |
| Regulatory Assets | 4,281.2 | 4,142.3 |
| Securitized Assets | 446.0 | 552.8 |
| Spent Nuclear Fuel and Decommissioning Trusts | 3,341.2 | 3,867.0 |
| Goodwill | 52.5 | 52.5 |
| Long-term Risk Management Assets | 284.1 | 267.0 |
| Operating Lease Assets | 645.0 | 578.3 |
| Deferred Charges and Other Noncurrent Assets | 3,717.8 | 4,398.3 |
| TOTAL OTHER NONCURRENT ASSETS | 12,767.8 | 13,858.2 |
| TOTAL ASSETS | $93,469.4 | $87,668.7 |

*See Notes to Financial Statements of Registrants beginning on page 81.*

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**  
 **CONSOLIDATED BALANCE SHEETS**  
 **LIABILITIES AND EQUITY**  
 **December 31, 2022 and 2021**  
 **(dollars in millions)**

|  | December 31, |  |
| --- | --- | --- |
|  | 2022 | 2021 |
| CURRENT LIABILITIES |  |  |
| Accounts Payable | $2,613.0 | $2,054.6 |
| Short-term Debt: |  |  |
| Securitized Debt for Receivables - AEP Credit | 750.0 | 750.0 |
| Other Short-term Debt | 3,362.2 | 1,864.0 |
| Total Short-term Debt | 4,112.2 | 2,614.0 |
| Long-term Debt Due Within One Year (December 31, 2022 and 2021 Amounts Include $218.2 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | 1,996.4 | 2,153.8 |
| Risk Management Liabilities | 145.2 | 75.4 |
| Customer Deposits | 370.0 | 321.6 |
| Accrued Taxes | 1,672.8 | 1,586.4 |
| Accrued Interest | 327.6 | 273.2 |
| Obligations Under Operating Leases | 113.4 | 97.6 |
| Liabilities Held for Sale | 1,955.7 | 1,880.9 |
| Other Current Liabilities | 1,261.1 | 1,369.2 |
| TOTAL CURRENT LIABILITIES | 14,567.4 | 12,426.7 |
| NONCURRENT LIABILITIES |  |  |
| Long-term Debt (December 31, 2022 and 2021 Amounts Include $755.3 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | 33,626.2 | 31,300.7 |
| Long-term Risk Management Liabilities | 345.3 | 230.3 |
| Deferred Income Taxes | 8,493.3 | 8,202.5 |
| Regulatory Liabilities and Deferred Investment Tax Credits | 7,999.6 | 8,686.3 |
| Asset Retirement Obligations | 2,860.8 | 2,676.2 |
| Employee Benefits and Pension Obligations | 257.3 | 328.4 |
| Obligations Under Operating Leases | 552.1 | 492.8 |
| Deferred Credits and Other Noncurrent Liabilities | 599.1 | 601.3 |
| TOTAL NONCURRENT LIABILITIES | 54,733.7 | 52,518.5 |
| TOTAL LIABILITIES | 69,301.1 | 64,945.2 |
| Rate Matters (Note 4) |  |  |
| Commitments and Contingencies (Note 6) |  |  |
| MEZZANINE EQUITY |  |  |
| Contingently Redeemable Performance Share Awards | 45.9 | 43.3 |
| TOTAL MEZZANINE EQUITY | 45.9 | 43.3 |
| EQUITY |  |  |
| Common Stock - Par Value - $6.50 Per Share: |  |  |
|  | 2022 | 2021 |
| Shares Authorized | 600,000,000 | 600,000,000 |
| Shares Issued | 525,099,321 | 524,416,175 |
| (11,233,240 and 20,204,160 Shares were Held in Treasury as of December 31, 2022 and 2021, Respectively) | 3,413.1 | 3,408.7 |
| Paid-in Capital | 8,051.0 | 7,172.6 |
| Retained Earnings | 12,345.6 | 11,667.1 |
| Accumulated Other Comprehensive Income (Loss) | 83.7 | 184.8 |
| TOTAL AEP COMMON SHAREHOLDERS' EQUITY | 23,893.4 | 22,433.2 |
| Noncontrolling Interests | 229.0 | 247.0 |
| TOTAL EQUITY | 24,122.4 | 22,680.2 |
| TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY | $93,469.4 | $87,668.7 |

See Notes to Financial Statements of Registrants beginning on page 81.

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# **AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**  
 **CONSOLIDATED STATEMENTS OF CASH FLOWS**  
 **For the Years Ended December 31, 2022, 2021 and 2020**  
 (in millions)

|  | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
| OPERATING ACTIVITIES |  |  |  |
| Net Income | $2,305.6 | $2,488.1 | $2,196.7 |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: |  |  |  |
| Depreciation and Amortization | 3,202.8 | 2,825.7 | 2,682.8 |
| Rockport Plant, Unit 2 Lease Amortization | - | 135.4 | 136.5 |
| Deferred Income Taxes | (137.2) | 107.6 | 196.1 |
| Loss on the Expected Sale of the Kentucky Operations | 363.3 | - | - |
| Asset Impairments and Other Related Charges | 48.8 | 11.6 | - |
| Impairment of Equity Method Investment | 188.0 | - | - |
| Allowance for Equity Funds Used During Construction | (133.7) | (139.7) | (148.1) |
| Mark-to-Market of Risk Management Contracts | 15.5 | 112.3 | 66.5 |
| Amortization of Nuclear Fuel | 82.9 | 85.3 | 87.5 |
| Pension Contributions to Qualified Plan Trust | - | - | (110.3) |
| Property Taxes | (41.2) | (68.0) | (43.3) |
| Deferred Fuel Over/Under-Recovery, Net | (319.2) | (1,647.9) | (31.8) |
| Gain on Sale of Mineral Rights | (116.3) | - | - |
| Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | (37.0) | - | - |
| Change in Regulatory Assets | (46.7) | (238.9) | (337.9) |
| Change in Other Noncurrent Assets | (187.7) | (126.6) | (151.0) |
| Change in Other Noncurrent Liabilities | 337.8 | 206.4 | (54.5) |
| Changes in Certain Components of Working Capital: |  |  |  |
| Accounts Receivable, Net | (681.7) | (119.7) | (129.3) |
| Fuel, Materials and Supplies | (313.9) | 300.2 | (142.9) |
| Accounts Payable | 489.2 | 200.6 | (35.3) |
| Accrued Taxes, Net | 105.4 | 218.7 | 20.1 |
| Rockport Plant, Unit 2 Operating Lease Payments | - | (147.7) | (147.7) |
| Other Current Assets | 109.0 | (151.3) | 34.3 |
| Other Current Liabilities | 54.3 | (212.2) | (255.5) |
| Net Cash Flows from Operating Activities | 5,288.0 | 3,839.9 | 3,832.9 |
| INVESTING ACTIVITIES |  |  |  |
| Construction Expenditures | (6,671.7) | (5,659.6) | (6,246.3) |
| Purchases of Investment Securities | (2,784.2) | (1,955.1) | (1,678.8) |
| Sales of Investment Securities | 2,743.8 | 1,901.4 | 1,644.3 |
| Acquisitions of Nuclear Fuel | (100.7) | (104.5) | (69.7) |
| Acquisition of the Dry Lake Solar Project | - | (114.4) | - |
| Acquisition of the North Central Wind Energy Facilities | (1,207.3) | (652.8) | - |
| Proceeds from Sales of Assets | 218.0 | 118.9 | 71.1 |
| Other Investing Activities | 50.3 | 32.2 | 45.5 |
| Net Cash Flows Used for Investing Activities | (7,751.8) | (6,433.9) | (6,233.9) |
| FINANCING ACTIVITIES |  |  |  |
| Issuance of Common Stock, Net | 826.5 | 600.5 | 155.0 |
| Issuance of Long-term Debt | 4,649.7 | 6,486.3 | 5,626.1 |
| Issuance of Short-term Debt with Original Maturities greater than 90 Days | 833.9 | 1,393.3 | 1,396.5 |
| Change in Short-term Debt with Original Maturities less than 90 Day, Net | 1,650.4 | (487.3) | (448.4) |
| Retirement of Long-term Debt | (2,345.4) | (2,989.3) | (1,339.8) |
| Redemption of Short-term Debt with Original Maturities greater than 90 Days | (986.1) | (771.3) | (1,307.1) |
| Principal Payments for Finance Lease Obligations | (309.5) | (64.0) | (61.7) |
| Dividends Paid on Common Stock | (1,645.2) | (1,519.5) | (1,424.9) |
| Redemption of Noncontrolling Interests | - | - | (100.2) |
| Other Financing Activities | (105.4) | (41.6) | (88.8) |
| Net Cash Flows from Financing Activities | 2,568.9 | 2,607.1 | 2,406.7 |
| Net Increase in Cash, Cash Equivalents and Restricted Cash | 105.1 | 13.1 | 5.7 |
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 451.4 | 438.3 | 432.6 |
| Cash, Cash Equivalents and Restricted Cash at End of Period | $556.5 | $451.4 | $438.3 |

See Notes to Financial Statements of Registrants beginning on page 81.

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## INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANTS

The notes to financial statements are a combined presentation for the Registrants. The following list indicates Registrants to which the notes apply. Specific disclosures within each note apply to all Registrants unless indicated otherwise.

| Note | Registrant | Page Number |
| --- | --- | --- |
| Organization and Summary of Significant Accounting Policies | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 82 |
| New Accounting Standards | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 99 |
| Comprehensive Income | AEP, AEP Texas, APCo, I&M, PSO, SWEPCo | 100 |
| Rate Matters | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 107 |
| Effects of Regulation | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 118 |
| Commitments, Guarantees and Contingencies | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 137 |
| Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments | AEP, AEP Texas, AEPTCo, PSO, SWEPCo | 145 |
| Benefit Plans | AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo | 152 |
| Business Segments | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 175 |
| Derivatives and Hedging | AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo | 180 |
| Fair Value Measurements | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 195 |
| Income Taxes | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 210 |
| Leases | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 222 |
| Financing Activities | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 228 |
| Stock-based Compensation | AEP | 239 |
| Related Party Transactions | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 244 |
| Variable Interest Entities and Equity Method Investments | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 252 |
| Property, Plant and Equipment | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 263 |
| Revenue from Contracts with Customers | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | 270 |
| Goodwill | AEP | 279 |
| Subsequent Events | AEP | 280 |

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# 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The disclosures in this note apply to all Registrants unless indicated otherwise.

## ORGANIZATION

The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

AEP provides competitive electric and gas supply for residential, commercial and industrial customers in deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier.

The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, AEP operates competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through Sabine, conducts lignite mining operations to fuel the Pirkey Plant.

## SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

### *Rates and Service Regulation*

AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over certain issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers continue to pay for certain legacy deferred generation-related costs through PUCO approved riders. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by REPs. AEP has one active REP in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind assets, the power from which is marketed and sold in ERCOT.

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The FERC also regulates the Registrants' wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas' retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEPTCo's seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO's OATT that are cost-based.

In 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.

In addition, the FERC regulates the SIA, Operating Agreement, TA and TCA, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 16 - Related Party Transactions for additional information.

### *Principles of Consolidation*

AEP's consolidated financial statements include its wholly-owned subsidiaries and VIEs, of which AEP is the primary beneficiary. The consolidated financial statements for AEP Texas include the Registrant Subsidiary, its wholly-owned subsidiaries, Transition Funding (consolidated VIEs) and Restoration Funding (a consolidated VIE). The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a consolidated VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (consolidated VIEs). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a consolidated VIE). Intercompany items are eliminated in consolidation.

The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee's equity earnings or losses is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.

AEP, I&M, PSO and SWEPCo have undivided ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included on the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 - Variable Interest Entities and Equity Method Investments and Note 18 - Property, Plant and Equipment for additional information. In October 2020, AEP Texas, PSO and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the Oklaunion Power Station site. See 'Oklaunion Power Station' section of Note 7 for additional information.

### *Accounting for the Effects of Cost-Based Regulation*

The Registrants' financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for 'Regulated Operations,' regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

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## *Use of Estimates*

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management's evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

## *Cash and Cash Equivalents*

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

## *AEP System Tax Allocation*

AEP and subsidiaries join in the filing of a consolidated federal income tax return. Historically, the allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries' financial statements. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable loss. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

## *Restricted Cash (Applies to AEP, AEP Texas and APCo)*

Restricted Cash primarily includes funds held by trustees for the payment of securitization bonds.

## *Reconciliation of Cash, Cash Equivalents and Restricted Cash*

The following tables provide a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the balance sheets that sum to the total of the same amounts shown on the statement of cash flows:

|  | December 31, 2022 |  |  |
| --- | --- | --- | --- |
|  | AEP | AEP Texas | APCo |
|  | (in millions) |  |  |
| Cash and Cash Equivalents | $509.4 | $0.1 | $7.5 |
| Restricted Cash | 47.1 | 32.7 | 14.4 |
| Total Cash, Cash Equivalents and Restricted Cash | $556.5 | $32.8 | $21.9 |

|  | December 31, 2021 |  |  |
| --- | --- | --- | --- |
|  | AEP | AEP Texas | APCo |
|  | (in millions) |  |  |
| Cash and Cash Equivalents | $403.4 | $0.1 | $2.5 |
| Restricted Cash | 48.0 | 30.4 | 17.6 |
| Total Cash, Cash Equivalents and Restricted Cash | $451.4 | $30.5 | $20.1 |

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### ***Other Temporary Investments (Applies to AEP)***

Other Temporary Investments primarily include marketable securities and investments by its protected cell of EIS. These securities have readily determinable fair values and are carried at fair value with changes in fair value recognized in net income. The cost of securities sold is based on the specific identification or weighted-average cost method. See “Fair Value Measurements of Other Temporary Investments” section of Note 11 for additional information.

### ***Inventory***

Fossil fuel inventories are carried at average cost with the exception of AGR, which carries these inventories at the lower of average cost or net realizable value. Materials and supplies inventories are carried at average cost.

### ***Accounts Receivable***

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.

### ***Allowance for Uncollectible Accounts***

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. The assessment is performed separately by each participating AEP subsidiary, which inherently contemplates any differences in geographical risk characteristics for the allowance. KPCo terminated selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result of the termination, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. For receivables related to KPCo and APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.

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### ***Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries)***

APCo, I&M, OPCo, PSO and SWEPCo do not have any significant customers that comprise 10% or more of their operating revenues. AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Accounts Receivable - Customers as of December 31:

| Significant Customers of AEP Texas: |  |  |  |
| --- | --- | --- | --- |
| Reliant Energy, Direct Energy and TXU Energy (a) | 2022 | 2021 | 2020 |
| Percentage of Total Revenues | 45% | 43% | 46% |
| Percentage of Accounts Receivable - Customers | 42% | 41% | 40% |

(a) In January 2021, NRG Energy, parent company of Reliant Energy, completed a deal to purchase Direct Energy from Centrica.

AEPTCo had significant transactions with AEP Subsidiaries which on a combined basis account for the following percentages of Total Revenues for the years ended December 31 and Total Accounts Receivable as of December 31:

| Significant Customers of AEPTCo: |  |  |  |
| --- | --- | --- | --- |
| AEP Subsidiaries | 2022 | 2021 | 2020 |
| Percentage of Total Revenues | 79% | 79% | 78% |
| Percentage of Total Accounts Receivable | 72% | 81% | 78% |

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

### ***Renewable Energy Credits (Applies to all Registrants except AEP Texas and AEPTCo)***

In regulated jurisdictions, the Registrants record renewable energy credits (RECs) at cost. For AEP’s competitive generation business, management records RECs at the lower of cost or net realizable value. The Registrants follow the inventory model for these RECs. RECs expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. RECs with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of RECs are reported in the Operating Activities section of the statements of cash flows. RECs that are consumed to meet applicable state renewable portfolio standards are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of RECs affects the determination of deferred fuel and REC costs.

### ***Property, Plant and Equipment***

#### ***Regulated***

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when the revenue received for

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removal costs accrued exceeds actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued.

The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

Nuclear fuel, including nuclear fuel in the fabrication phase, is included in Other Property, Plant and Equipment on the balance sheets.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be written down to its then current estimated fair value, with the change charged to expense, and the asset is removed from plant-in-service or CWIP. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

#### *Nonregulated*

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.

#### *Allowance for Funds Used During Construction and Interest Capitalization*

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense on the statements of income. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

#### *Asset Retirement Obligations (Applies to all Registrants except AEPTCo)*

The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal-mining facilities. I&M records ARO for the decommissioning of the Cook Plant. AROs are computed as the present value of the estimated costs associated with the future retirement of an asset and are recorded in the period in which the liability is incurred. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be decommissioned, inflation, and discount rate, which may change significantly over time. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since

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the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

### *Valuation of Nonderivative Financial Instruments*

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.

### *Fair Value Measurements of Assets and Liabilities (Applies to all Registrants except AEPTCo)*

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes.

Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities

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compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

### ***Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)***

The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are incorporated into the development of future fuel rates billed to or refunded to customers. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen, non-existent or not applicable to merchant operations, changes in fuel costs or sharing of Off-system Sales impact earnings.

### ***Revenue Recognition***

#### ***Regulatory Accounting***

The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are reviewed for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

#### ***Retail and Wholesale Supply and Delivery of Electricity***

The Registrants recognize revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. In accordance with the applicable state commission’s regulatory

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treatment, PSO and SWEPCo do not include the fuel portion in unbilled revenue, but rather recognize such revenues when billed to customers.

Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year's rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for 'Regulated Operations'. An estimated annual true-up is recorded by the Registrants in the fourth quarter of each calendar year and a final annual true-up is recognized by the Registrants in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable - Affiliated Companies or Accounts Payable - Affiliated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as Regulatory Assets or Regulatory Liabilities on the balance sheets. See Note 19 - Revenue from Contracts with Customers for additional information.

#### *Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities*

Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP's nonregulated subsidiaries are reported as gross purchases or sales.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction's facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues.

In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

#### *Energy Marketing and Risk Management Activities (Applies to all Registrants except AEPTCo)*

The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy 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. Certain energy marketing and risk management transactions are with RTOs.

The Registrants recognize revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied. Expenses from marketing and risk management transactions that are not derivatives are also recognized upon delivery of the commodity.

The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. Unrealized MTM gains and losses are included on the balance sheets as Risk

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Management Assets or Liabilities, as appropriate, and on the statements of income in Total Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.

### ***Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M)***

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over approximately 18 months, beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.

### ***Maintenance***

The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

### ***Income Taxes and Investment and Production Tax Credits***

The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

AEP and subsidiaries apply the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the utility is able to utilize the ITC on a stand-alone basis. Alternatively, PTCs reduce income tax expense as they are earned. PTCs are earned when electricity is produced.

The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense on the statements of income.

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### ***Excise Taxes (Applies to all Registrants except AEPTCo)***

As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.

### ***Debt***

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.

### ***Goodwill (Applies to AEP)***

When the Registrants acquire a business, as defined by the accounting guidance for 'Business Combinations,' management recognizes all acquired assets and liabilities at their fair value. To the extent that consideration exceeds the net fair value of the identified assets and liabilities, goodwill is recognized on the balance sheets. Goodwill is not amortized. Management tests acquired goodwill at the reporting unit level for impairment at least annually at its estimated fair value. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods.

### ***Pension and OPEB Plans (Applies to all Registrants except AEPTCo)***

AEP sponsors a qualified pension plan and two unfunded non-qualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a non-qualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries account for their participation in the AEP sponsored pension and OPEB plans using multiple-employer accounting. See Note 8 - Benefit Plans for additional information including significant accounting policies associated with the plans.

### ***Investments Held in Trust for Future Liabilities (Applies to all Registrants except AEPTCo)***

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and SNF disposal. All of the trust funds' investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the 'Fair Value Measurements and Disclosures' accounting guidance.

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## *Benefit Plans*

All benefit plan assets are invested in accordance with each plan's investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP's benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:

- Maintaining a long-term investment horizon.
- Diversifying assets to help control volatility of returns at acceptable levels.
- Managing fees, transaction costs and tax liabilities to maximize investment earnings.
- Using active management of investments where appropriate risk/return opportunities exist.
- Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
- Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows:

| Pension Plan Assets | Target |
| --- | --- |
| Equity | 30% |
| Fixed Income | 54% |
| Other Investments | 15% |
| Cash and Cash Equivalents | 1% |

| OPEB Plans Assets | Target |
| --- | --- |
| Equity | 59% |
| Fixed Income | 40% |
| Cash and Cash Equivalents | 1% |

The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

For equity investments, the concentration limits are generally as follows:

- No security in excess of 5% of all equities.
- Cash equivalents must be less than 10% of an investment manager's equity portfolio.
- No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager's equity portfolio.
- No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, each investment manager's portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are

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diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.

A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset's market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program's objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2022 and 2021, the fair value of securities on loan as part of the program was $83 million and $137 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2022 and 2021.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees' Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.

#### *Nuclear Trust Funds (Applies to AEP and I&M)*

Nuclear decommissioning and SNF trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and SNF disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

- Acceptable investments (rated investment grade or above when purchased).
- Maximum percentage invested in a specific type of investment.
- Prohibition of investment in obligations of AEP, I&M or their affiliates.
- Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by an external investment manager that must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

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I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies debt securities in the trust funds as available-for-sale due to their long-term purpose.

Other-than-temporary impairments for investments in debt securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains, unrealized losses and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

### ***Comprehensive Income (Loss) (Applies to all Registrants except AEPTCo and OPCo)***

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

### ***Stock-Based Compensation Plans***

As of December 31, 2022, AEP had performance shares and restricted stock units outstanding under the American Electric Power System 2015 Long-Term Incentive Plan (2015 LTIP). Upon vesting, all outstanding performance shares and restricted stock units settle in AEP common stock. All performance units awarded prior to 2017 and restricted stock units granted after January 1, 2013 and prior to January 1, 2017 that vested to executive officers were settled in cash. During 2019, all of the remaining performance units and restricted stock units that settle in cash were settled. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries.

AEP maintains a variety of tax qualified and non-qualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan (SORP), which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance shares granted to employees under the 2015 LTIP and previous long-term incentive plans. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. All AEP career shares are settled in shares of AEP common stock after the executive’s service with AEP ends.

Performance shares awarded after January 1, 2017 are classified as temporary equity in the Mezzanine Equity section of the balance sheets until the awards vest. Upon vesting, the performance shares are classified as permanent equity. These awards may be settled in cash upon an employee’s qualifying termination due to a change in control. Because such event is not solely within the control of the company, these awards are classified outside of permanent equity until the awards vest.

AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units were payable in cash

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to directors after their service ends. Effective in June 2022, these stock units became payable in AEP common stock rather than cash.

Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2022, 2021 and 2020 is based on the number of outstanding awards at the end of each period without a reduction for estimated forfeitures. AEP accounts for forfeitures in the period in which they occur.

For the years ended December 31, 2022, 2021 and 2020, compensation costs are included in Net Income for the performance shares, career shares, restricted stock units and the non-employee director stock units. Compensation costs may also be capitalized. See Note 15 - Stock-based Compensation for additional information.

### *Equity Method Investments in Unconsolidated Entities (Applies to AEP and SWEPCo)*

The equity method of accounting is used for equity investments where either AEP or SWEPCo exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee's equity earnings or losses is included in Equity Earnings (Loss) of Unconsolidated Subsidiaries on the statements of income. AEP and SWEPCo regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recognized when the investment has experienced a loss in value that is other-than-temporary in nature.

AEP's significant equity method investments include ETT, DHLC and four joint venture interests which own distinct wind generation facilities. See Note 17 - Variable Interest Entities and Equity Method Investments for additional information.

### *Earnings Per Share (EPS) (Applies to AEP)*

Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted-average outstanding common shares, assuming conversion of all potentially dilutive stock awards.

The following table presents AEP's basic and diluted EPS calculations included on the statements of income:

|  | Years Ended December 31, |  |  |  |  |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | 2022 |  | 2021 |  | 2020 |  |
|  | (in millions, except per-share data) |  |  |  |  |  |
|  | $/share |  | $/share |  | $/share |  |
| Earnings Attributable to AEP Common Shareholders | $2,307.2 |  | $2,488.1 |  | $2,200.1 |  |
| Weighted-Average Number of Basic AEP Common Shares Outstanding | 511.8 | $4.51 | 500.5 | $4.97 | 495.7 | $4.44 |
| Weighted-Average Dilutive Effect of Stock-Based Awards | 1.7 | (0.02) | 1.3 | (0.01) | 1.5 | (0.02) |
| Weighted-Average Number of Diluted AEP Common Shares Outstanding | 513.5 | $4.49 | 501.8 | $4.96 | 497.2 | $4.42 |

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the years ended December 31, 2022, 2021 and 2020, as the dilutive stock price thresholds were not met. See Note 14 - Financing Activities for additional information related to Equity Units.

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There were no antidilutive shares outstanding as of December 31, 2022 and 2021. There were 128 thousand antidilutive shares outstanding as of December 31, 2020.

### *Supplementary Income Statement Information*

The following tables provide the components of Depreciation and Amortization for the years ended December 31, 2022, 2021 and 2020:

#### **2022**

| Depreciation and Amortization | AEP | AEP Texas | AEPTCo | APCo | I&M | OPCo | PSO | SWEPCo |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | (in millions) |  |  |  |  |  |  |  |
| Depreciation and Amortization of Property, Plant and Equipment | $3,072.8 | $363.5 | $346.2 | $576.1 | $511.9 | $293.1 | $226.2 | $319.3 |
| Amortization of Certain Securitized Assets | 93.3 | 93.3 | - | - | - | - | - | - |
| Amortization of Regulatory Assets and Liabilities | 36.7 | (4.4) | - | (0.2) | 15.3 | 1.2 | 3.9 | 5.5 |
| Total Depreciation and Amortization | $3,202.8 | $452.4 | $346.2 | $575.9 | $527.2 | $294.3 | $230.1 | $324.8 |

#### **2021**

| Depreciation and Amortization | AEP | AEP Texas | AEPTCo | APCo | I&M | OPCo | PSO | SWEPCo |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | (in millions) |  |  |  |  |  |  |  |
| Depreciation and Amortization of Property, Plant and Equipment | $2,717.1 | $327.2 | $297.3 | $547.0 | $424.9 | $301.1 | $185.9 | $292.9 |
| Amortization of Certain Securitized Assets | 64.2 | 64.2 | - | - | - | - | - | - |
| Amortization of Regulatory Assets and Liabilities | 44.4 | (4.4) | - | (0.8) | 21.1 | 2.2 | 10.7 | 2.1 |
| Total Depreciation and Amortization | $2,825.7 | $387.0 | $297.3 | $546.2 | $446.0 | $303.3 | $196.6 | $295.0 |

#### **2020**

| Depreciation and Amortization | AEP | AEP Texas | AEPTCo | APCo | I&M | OPCo | PSO | SWEPCo |
| --- | --- | --- | --- | --- | --- | --- | --- | --- |
|  | (in millions) |  |  |  |  |  |  |  |
| Depreciation and Amortization of Property, Plant and Equipment | $2,487.5 | $364.2 | $249.0 | $507.8 | $393.3 | $275.0 | $171.9 | $271.2 |
| Amortization of Certain Securitized Assets | 171.3 | 171.3 | - | - | - | - | - | - |
| Amortization of Regulatory Assets and Liabilities | 24.0 | (5.7) | - | (0.3) | 18.3 | 1.6 | 1.6 | 1.5 |
| Total Depreciation and Amortization | $2,682.8 | $529.8 | $249.0 | $507.5 | $411.6 | $276.6 | $173.5 | $272.7 |

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# *Supplementary Cash Flow Information (Applies to AEP)*

| Cash Flow Information | Years Ended December 31, |  |  |
| --- | --- | --- | --- |
|  | 2022 | 2021 | 2020 |
|  | (in millions) |  |  |
| Cash Paid (Received) for: |  |  |  |
| Interest, Net of Capitalized Amounts | $1,286.3 | $1,137.2 | $1,029.1 |
| Income Taxes | 116.8 | 13.2 | (49.1) |
| Noncash Investing and Financing Activities: |  |  |  |
| Acquisitions Under Finance Leases | 31.8 | 287.6 | 44.2 |
| Construction Expenditures Included in Current Liabilities as of December 31, | 1,258.9 | 1,180.4 | 975.4 |
| Construction Expenditures Included in Noncurrent Liabilities as of December 31, | - | - | 5.5 |
| Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, | - | - | 33.4 |
| Noncash Contribution of Assets to Cedar Creek Project | - | (9.3) | - |
| Noncontrolling Interest Assumed - Dry Lake Solar Project | - | 35.3 | - |
| Forward Equity Purchase Contracts Included in Current and Noncurrent Liabilities as of December 31, | - | - | 110.6 |

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## 2. NEW ACCOUNTING STANDARDS

The disclosures in this note apply to all Registrants unless indicated otherwise.

During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. There are no new standards expected to have a material impact on the Registrants’ financial statements.

99

### 3. COMPREHENSIVE INCOME

The disclosures in this note apply to all Registrants except AEPTCo and OPCo.

#### *Presentation of Comprehensive Income*

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2022, 2021 and 2020. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.

#### AEP

| For the Year Ended December 31, 2022 | Cash Flow Hedges |  | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- | --- |
|  | Commodity | Interest Rate | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2021 | $163.7 | $(21.3) | $115.6 | $(73.2) | $184.8 |
| Change in Fair Value Recognized in AOCI, Net of Tax | 477.3 | 18.4 (a) | - | (155.4) | 340.3 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |  |
| Generation & Marketing Revenues (b) | 0.1 | - | - | - | 0.1 |
| Purchased Electricity for Resale (b) | (528.6) | - | - | - | (528.6) |
| Interest Expense (b) | - | 4.0 | - | - | 4.0 |
| Amortization of Prior Service Cost (Credit) | - | - | (21.8) | - | (21.8) |
| Amortization of Actuarial (Gains) Losses | - | - | 8.6 | - | 8.6 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (528.5) | 4.0 | (13.2) | - | (537.7) |
| Income Tax (Expense) Benefit | (111.0) | 0.8 | (2.8) | - | (113.0) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (417.5) | 3.2 | (10.4) | - | (424.7) |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI | - | - | - | (21.1) | (21.1) |
| Income Tax (Expense) Benefit | - | - | - | (4.4) | (4.4) |
| Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit | - | - | - | (16.7) | (16.7) |
| Net Current Period Other Comprehensive Income (Loss) | 59.8 | 21.6 | (10.4) | (172.1) | (101.1) |
| Balance in AOCI as of December 31, 2022 | $223.5 | $0.3 | $105.2 | $(245.3) | $83.7 |

100

# **AEP**

| For the Year Ended December 31, 2021 | Cash Flow Hedges |  | Pension and OPEB |  |  |
| --- | --- | --- | --- | --- | --- |
|  | Commodity | Interest Rate | Amortization of Deferred Costs | Changes in Funded Status | Total |
| (in millions) |  |  |  |  |  |
| Balance in AOCI as of December 31, 2020 | $(60.6) | $(47.5) | $123.7 | $(100.7) | $(85.1) |
| Change in Fair Value Recognized in AOCI, Net of Tax | 488.2 | 21.1 (a) | - | 27.5 | 536.8 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |  |
| Generation & Marketing Revenues (b) | 0.7 | - | - | - | 0.7 |
| Purchased Electricity for Resale (b) | (334.8) | - | - | - | (334.8) |
| Interest Expense (b) | - | 6.5 | - | - | 6.5 |
| Amortization of Prior Service Cost (Credit) | - | - | (19.4) | - | (19.4) |
| Amortization of Actuarial (Gains) Losses | - | - | 9.1 | - | 9.1 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (334.1) | 6.5 | (10.3) | - | (337.9) |
| Income Tax (Expense) Benefit | (70.2) | 1.4 | (2.2) | - | (71.0) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (263.9) | 5.1 | (8.1) | - | (266.9) |
| Net Current Period Other Comprehensive Income (Loss) | 224.3 | 26.2 | (8.1) | 27.5 | 269.9 |
| Balance in AOCI as of December 31, 2021 | $163.7 | $(21.3) | $115.6 | $(73.2) | $184.8 |

| For the Year Ended December 31, 2020 | Cash Flow Hedges |  | Pension and OPEB |  |  |
| --- | --- | --- | --- | --- | --- |
|  | Commodity | Interest Rate | Amortization of Deferred Costs | Changes in Funded Status | Total |
| (in millions) |  |  |  |  |  |
| Balance in AOCI as of December 31, 2019 | $(103.5) | $(11.5) | $130.7 | $(163.4) | $(147.7) |
| Change in Fair Value Recognized in AOCI, Net of Tax | (89.2) | (39.9) (a) | - | 62.7 | (66.4) |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |  |
| Generation & Marketing Revenues (b) | (0.4) | - | - | - | (0.4) |
| Purchased Electricity for Resale (b) | 167.6 | - | - | - | 167.6 |
| Interest Expense (b) | - | 4.9 | - | - | 4.9 |
| Amortization of Prior Service Cost (Credit) | - | - | (19.2) | - | (19.2) |
| Amortization of Actuarial (Gains) Losses | - | - | 10.3 | - | 10.3 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 167.2 | 4.9 | (8.9) | - | 163.2 |
| Income Tax (Expense) Benefit | 35.1 | 1.0 | (1.9) | - | 34.2 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 132.1 | 3.9 | (7.0) | - | 129.0 |
| Net Current Period Other Comprehensive Income (Loss) | 42.9 | (36.0) | (7.0) | 62.7 | 62.6 |
| Balance in AOCI as of December 31, 2020 | $(60.6) | $(47.5) | $123.7 | $(100.7) | $(85.1) |

101

# **AEP Texas**

| For the Year Ended December 31, 2022 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2021 | $(1.3) | $5.3 | $(10.5) | $(6.5) |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | (3.2) | (3.2) |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 1.3 | - | - | 1.3 |
| Amortization of Prior Service Cost (Credit) | - | (0.1) | - | (0.1) |
| Amortization of Actuarial (Gains) Losses | - | 0.2 | - | 0.2 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 1.3 | 0.1 | - | 1.4 |
| Income Tax (Expense) Benefit | 0.3 | - | - | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.0 | 0.1 | - | 1.1 |
| Net Current Period Other Comprehensive Income (Loss) | 1.0 | 0.1 | (3.2) | (2.1) |
| Balance in AOCI as of December 31, 2022 | $(0.3) | $5.4 | $(13.7) | $(8.6) |

| For the Year Ended December 31, 2021 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2020 | $(2.3) | $5.1 | $(11.7) | $(8.9) |
| Change in Fair Value Recognized in AOCI, Net of Tax | 0.1 | - | 1.2 | 1.3 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 1.2 | - | - | 1.2 |
| Amortization of Prior Service Cost (Credit) | - | (0.1) | - | (0.1) |
| Amortization of Actuarial (Gains) Losses | - | 0.3 | - | 0.3 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 1.2 | 0.2 | - | 1.4 |
| Income Tax (Expense) Benefit | 0.3 | - | - | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 0.9 | 0.2 | - | 1.1 |
| Net Current Period Other Comprehensive Income (Loss) | 1.0 | 0.2 | 1.2 | 2.4 |
| Balance in AOCI as of December 31, 2021 | $(1.3) | $5.3 | $(10.5) | $(6.5) |

| For the Year Ended December 31, 2020 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2019 | $(3.4) | $4.9 | $(14.3) | $(12.8) |
| Change in Fair Value Recognized in AOCI, Net of Tax | 0.1 | - | 2.6 | 2.7 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 1.3 | - | - | 1.3 |
| Amortization of Prior Service Cost (Credit) | - | (0.1) | - | (0.1) |
| Amortization of Actuarial (Gains) Losses | - | 0.3 | - | 0.3 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 1.3 | 0.2 | - | 1.5 |
| Income Tax (Expense) Benefit | 0.3 | - | - | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.0 | 0.2 | - | 1.2 |
| Net Current Period Other Comprehensive Income (Loss) | 1.1 | 0.2 | 2.6 | 3.9 |
| Balance in AOCI as of December 31, 2020 | $(2.3) | $5.1 | $(11.7) | $(8.9) |

102

# **APCo**

| For the Year Ended December 31, 2022 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status |  |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2021 | $7.5 | $1.2 | $15.7 | $24.4 |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | (24.1) | (24.1) |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | (1.0) | - | - | (1.0) |
| Amortization of Prior Service Cost (Credit) | - | (5.4) | - | (5.4) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (1.0) | (5.4) | - | (6.4) |
| Income Tax (Expense) Benefit | (0.2) | (1.1) | - | (1.3) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (0.8) | (4.3) | - | (5.1) |
| Net Current Period Other Comprehensive Income (Loss) | (0.8) | (4.3) | (24.1) | (29.2) |
| Balance in AOCI as of December 31, 2022 | $6.7 | $(3.1) | $(8.4) | $(4.8) |

| For the Year Ended December 31, 2021 | Cash Flow Hedges - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status |  |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2020 | $(0.8) | $5.4 | $2.6 | $7.2 |
| Change in Fair Value Recognized in AOCI, Net of Tax | 9.2 | - | 13.1 | 22.3 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | (1.1) | - | - | (1.1) |
| Amortization of Prior Service Cost (Credit) | - | (5.3) | - | (5.3) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (1.1) | (5.3) | - | (6.4) |
| Income Tax (Expense) Benefit | (0.2) | (1.1) | - | (1.3) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (0.9) | (4.2) | - | (5.1) |
| Net Current Period Other Comprehensive Income (Loss) | 8.3 | (4.2) | 13.1 | 17.2 |
| Balance in AOCI as of December 31, 2021 | $7.5 | $1.2 | $15.7 | $24.4 |

| For the Year Ended December 31, 2020 | Cash Flow Hedges - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status |  |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2019 | $0.9 | $9.2 | $(5.1) | $5.0 |
| Change in Fair Value Recognized in AOCI, Net of Tax | (0.7) | - | 7.7 | 7.0 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | (1.3) | - | - | (1.3) |
| Amortization of Prior Service Cost (Credit) | - | (5.3) | - | (5.3) |
| Amortization of Actuarial (Gains) Losses | - | 0.5 | - | 0.5 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (1.3) | (4.8) | - | (6.1) |
| Income Tax (Expense) Benefit | (0.3) | (1.0) | - | (1.3) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (1.0) | (3.8) | - | (4.8) |
| Net Current Period Other Comprehensive Income (Loss) | (1.7) | (3.8) | 7.7 | 2.2 |
| Balance in AOCI as of December 31, 2020 | $(0.8) | $5.4 | $2.6 | $7.2 |

103

# **I&M**

| For the Year Ended December 31, 2022 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  |  |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status | Total |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2021 | $(6.7) | $4.7 | $0.7 | $(1.3) |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | (0.3) | (0.3) |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 2.0 | - | - | 2.0 |
| Amortization of Prior Service Cost (Credit) | - | (0.8) | - | (0.8) |
| Amortization of Actuarial (Gains) Losses | - | 0.4 | - | 0.4 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 2.0 | (0.4) | - | 1.6 |
| Income Tax (Expense) Benefit | 0.4 | (0.1) | - | 0.3 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.6 | (0.3) | - | 1.3 |
| Net Current Period Other Comprehensive Income (Loss) | 1.6 | (0.3) | (0.3) | 1.0 |
| Balance in AOCI as of December 31, 2022 | $(5.1) | $4.4 | $0.4 | $(0.3) |

| For the Year Ended December 31, 2021 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  |  |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status | Total |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2020 | $(8.3) | $4.8 | $(3.5) | $(7.0) |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | 4.2 | 4.2 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 2.0 | - | - | 2.0 |
| Amortization of Prior Service Cost (Credit) | - | (0.8) | - | (0.8) |
| Amortization of Actuarial (Gains) Losses | - | 0.7 | - | 0.7 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 2.0 | (0.1) | - | 1.9 |
| Income Tax (Expense) Benefit | 0.4 | - | - | 0.4 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.6 | (0.1) | - | 1.5 |
| Net Current Period Other Comprehensive Income (Loss) | 1.6 | (0.1) | 4.2 | 5.7 |
| Balance in AOCI as of December 31, 2021 | $(6.7) | $4.7 | $0.7 | $(1.3) |

| For the Year Ended December 31, 2020 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  |  |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs | Changes in Funded Status | Total |
|  |  | (in millions) |  |  |
| Balance in AOCI as of December 31, 2019 | $(9.9) | $4.9 | $(6.6) | $(11.6) |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | 3.1 | 3.1 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 2.0 | - | - | 2.0 |
| Amortization of Prior Service Cost (Credit) | - | (0.8) | - | (0.8) |
| Amortization of Actuarial (Gains) Losses | - | 0.7 | - | 0.7 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 2.0 | (0.1) | - | 1.9 |
| Income Tax (Expense) Benefit | 0.4 | - | - | 0.4 |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.6 | (0.1) | - | 1.5 |
| Net Current Period Other Comprehensive Income (Loss) | 1.6 | (0.1) | 3.1 | 4.6 |
| Balance in AOCI as of December 31, 2020 | $(8.3) | $4.8 | $(3.5) | $(7.0) |

104

PSO

| For the Year Ended December 31, 2022 | Cash Flow Hedge - Interest Rate (in millions) |
| --- | --- |
| Balance in AOCI as of December 31, 2021 | $ - |
| Change in Fair Value Recognized in AOCI, Net of Tax | 1.3 |
| Amount of (Gain) Loss Reclassified from AOCI |  |
| Interest Expense (b) | - |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | - |
| Income Tax (Expense) Benefit | - |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | - |
| Net Current Period Other Comprehensive Income (Loss) | 1.3 |
| Balance in AOCI as of December 31, 2022 | $1.3 |

| For the Year Ended December 31, 2021 | Cash Flow Hedge - Interest Rate (in millions) |
| --- | --- |
| Balance in AOCI as of December 31, 2020 | $0.1 |
| Change in Fair Value Recognized in AOCI, Net of Tax | - |
| Amount of (Gain) Loss Reclassified from AOCI |  |
| Interest Expense (b) | (0.1) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (0.1) |
| Income Tax (Expense) Benefit | - |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (0.1) |
| Net Current Period Other Comprehensive Income (Loss) | (0.1) |
| Balance in AOCI as of December 31, 2021 | $ - |

| For the Year Ended December 31, 2020 | Cash Flow Hedge - Interest Rate (in millions) |
| --- | --- |
| Balance in AOCI as of December 31, 2019 | $1.1 |
| Change in Fair Value Recognized in AOCI, Net of Tax | - |
| Amount of (Gain) Loss Reclassified from AOCI |  |
| Interest Expense (b) | (1.3) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (1.3) |
| Income Tax (Expense) Benefit | (0.3) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (1.0) |
| Net Current Period Other Comprehensive Income (Loss) | (1.0) |
| Balance in AOCI as of December 31, 2020 | $0.1 |

105

# **SWEPCo**

| For the Year Ended December 31, 2022 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2021 | $1.2 | $(4.4) | $9.9 | $6.7 |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | (9.2) | (9.2) |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | (0.1) | - | - | (0.1) |
| Amortization of Prior Service Cost (Credit) | - | (2.0) | - | (2.0) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | (0.1) | (2.0) | - | (2.1) |
| Income Tax (Expense) Benefit | - | (0.4) | - | (0.4) |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | (0.1) | (1.6) | - | (1.7) |
| Net Current Period Other Comprehensive Income (Loss) | (0.1) | (1.6) | (9.2) | (10.9) |
| Balance in AOCI as of December 31, 2022 | $1.1 | $(6.0) | $0.7 | $(4.2) |

| For the Year Ended December 31, 2021 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2020 | $(0.3) | $(2.8) | $5.0 | $1.9 |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | 4.9 | 4.9 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 1.9 | - | - | 1.9 |
| Amortization of Prior Service Cost (Credit) | - | (2.0) | - | (2.0) |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 1.9 | (2.0) | - | (0.1) |
| Income Tax (Expense) Benefit | 0.4 | (0.4) | - | - |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.5 | (1.6) | - | (0.1) |
| Net Current Period Other Comprehensive Income (Loss) | 1.5 | (1.6) | 4.9 | 4.8 |
| Balance in AOCI as of December 31, 2021 | $1.2 | $(4.4) | $9.9 | $6.7 |

| For the Year Ended December 31, 2020 | Cash Flow Hedge - Interest Rate | Pension and OPEB |  | Total |
| --- | --- | --- | --- | --- |
|  |  | Amortization of Deferred Costs (in millions) | Changes in Funded Status |  |
| Balance in AOCI as of December 31, 2019 | $(1.8) | $(1.3) | $1.8 | $(1.3) |
| Change in Fair Value Recognized in AOCI, Net of Tax | - | - | 3.2 | 3.2 |
| Amount of (Gain) Loss Reclassified from AOCI |  |  |  |  |
| Interest Expense (b) | 1.9 | - | - | 1.9 |
| Amortization of Prior Service Cost (Credit) | - | (2.0) | - | (2.0) |
| Amortization of Actuarial (Gains) Losses | - | 0.1 | - | 0.1 |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | 1.9 | (1.9) | - | - |
| Income Tax (Expense) Benefit | 0.4 | (0.4) | - | - |
| Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | 1.5 | (1.5) | - | - |
| Net Current Period Other Comprehensive Income (Loss) | 1.5 | (1.5) | 3.2 | 3.2 |
| Balance in AOCI as of December 31, 2020 | $(0.3) | $(2.8) | $5.0 | $1.9 |

(a) The change in fair value includes $(10) million, $(7) million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively, related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.

106

#### **4. RATE MATTERS**

The disclosures in this note apply to all Registrants unless indicated otherwise.

The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants' recent significant rate orders and pending rate filings are addressed in this note.

##### **AEP Texas Rate Matters (Applies to AEP and AEP Texas)**

###### ***AEP Texas Interim Transmission and Distribution Rates***

Through December 31, 2022, AEP Texas' cumulative revenues from interim base rate increases that are subject to review is approximately $614 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.

##### **APCo and WPCo Rate Matters (Applies to AEP and APCo)**

###### ***2017-2019 Virginia Triennial Review***

In November 2020, the Virginia SCC issued an order on APCo's 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a statutory 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). APCo appealed this order and a similar order on reconsideration to the Virginia Supreme Court in March 2021, alleging the Virginia SCC erred in finding that costs associated with asset impairments related to APCo early retirement determinations for certain generation facilities should not be attributed to the 2017-2019 test periods under review and deemed fully recovered in the period recorded. In August 2022, the Virginia Supreme Court agreed with this portion of APCo's appeal and remanded this issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings. In September 2022, as a result of the Virginia Supreme Court ruling, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band.

In response to the Virginia Supreme Court's August 2022 opinion, the Virginia SCC initiated remand proceedings and, in December 2022, issued an order that: (a) approved APCo's requested $37 million regulatory asset related to previously incurred costs as a result of APCo earning below its 2017-2019 authorized ROE band, (b) authorized a $28 million annual increase in APCo Virginia base rates effective October 2022 and (c) approved a rider to recover approximately $48 million related to this APCo Virginia base rate increase for the period January 2021 through September 2022. APCo's 2022 financial statements reflect the impact of the Virginia SCC's December 2022 order.

###### ***2020-2022 Virginia Triennial Review***

In March 2023, APCo will submit its required Virginia earnings test calculation to the Virginia SCC for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the authorized ROE band, related to major storms, the early retirement of fossil fuel generating assets and certain projects necessary to comply with state and federal environmental legislation. As of December 31, 2022, APCo has deferred approximately $38 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined

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that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and cash flows and impact financial condition.

### ***CCR/ELG Compliance Plan Filings***

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. In August 2021, the Virginia SCC issued an order approving recovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants through an active rider. The order also denied APCo’s request to recover the cost of ELG investments and denied recovery of previously incurred ELG costs, but did not preclude APCo from refiling for approval. Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider.

In March 2022, APCo refiled for approval to recover the Virginia jurisdictional share of ELG investments at the Amos and Mountaineer Plants. The Virginia SCC issued a November 2022 order approving this request.

### ***2021 and 2022 ENEC (Expanded Net Energy Cost) Filings***

In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.

In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudence review.

In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.

In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudence review. In February 2023, the WVPSC issued an order stating that the commission will not grant additional rate increases for fuel costs until the WVPSC staff completes its prudence review. As of December 31, 2022, the Companies’ cumulative ENEC under-recovery was $520 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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### ***June 2022 West Virginia Storm Costs***

In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of December 31, 2022, the Companies incurred and deferred an estimated $17 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

### **ETT Rate Matters (Applies to AEP)**

#### ***ETT Interim Transmission Rates***

AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through December 31, 2022, AEP's share of ETT's cumulative revenues that are subject to review is approximately $1.5 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring.

In December 2022, ETT and various intervenors filed a stipulation and settlement agreement with the PUCT. The agreement maintains ETT's previously allowed ROE and capital structure and includes: (a) a $14 million decrease to the current annual revenue requirement effective February 1, 2023, (b) a provision that ETT must make an interim transmission cost of service filing by June 1, 2023, (c) a $2 million line item decrease to the revenue requirement determined in each interim transmission cost of service filing until the filing of the next comprehensive base rate review and (d) no determination of prudence on any transmission investment added since ETT's last comprehensive base rate review, which would leave the $1.5 billion of cumulative revenues above subject to review in the next comprehensive base rate review. In February 2023, the PUCT approved the stipulation and settlement agreement. As part of the approved agreement, new rates will be implemented in February 2023 and ETT is required to file for a comprehensive base rate review no later than February 1, 2025.

### **I&M Rate Matters (Applies to AEP and I&M)**

#### ***Michigan Power Supply Cost Recovery (PSCR) Reconciliation***

In April 2022, an ALJ issued a PFD for I&M's PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In February 2023, the MPSC issued an order resulting in a $1 million disallowance of 2020 OVEC costs.

#### ***Indiana Earnings Test Filings***

I&M is required by Indiana law to submit an earnings test evaluation for the most recent one-year and five-year periods as part of I&M's semi-annual Indiana FAC filings. These earnings test evaluations require I&M to include a credit in the FAC factor computation for periods in which I&M earned above its authorized return for both the one-year and five-year periods. The credit is determined as 50% of the lower of the one-year or five-year earnings above the authorized level. In August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2022, which calculated a credit due to customers of $14 million. In October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in November 2022 through the FAC. As of December 31, 2022, I&M's financial statements adequately reflect the estimated impact of I&M's upcoming Indiana earnings test filings. If it is determined that I&M's over-earnings exceed what has been recorded, it could reduce future net income and cash flows and impact financial condition.

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## ***2022 Michigan Integrated Resource Plan (IRP) Filing***

In February 2022, I&M filed a request with the MPSC for approval of its 2022 IRP. Included in that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission's order in the filing. These resources include the new generation resources expected to be in-service by 2028 and demand-side resources, including load management programs and conservation voltage reduction investments. I&M is also requesting MPSC approval of I&M's Rockport Plant, Unit 2 transition plan consistent with that approved by the IURC, including certain cost recovery related to remaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and future use of Rockport Plant, Unit 2 as a capacity resource. In addition, I&M has made requests for approval of a financial incentive on certain power purchase agreements and load management programs. As of December 31, 2022, I&M's total net book value for these Rockport Plant, Unit 2 leasehold improvements was approximately $17 million on a Michigan jurisdictional basis.

In November 2022, I&M filed a settlement agreement, which included a Rockport Plant, Unit 2 transition plan. Under this plan, I&M Michigan ratepayers will receive a jurisdictional share of post-lease revenues in excess of costs from Rockport Plant, Unit 2's operations as a merchant facility. In addition, I&M will continue to recover the remaining net book value of Rockport Plant, Unit 2 leasehold improvements through 2028, including a pretax return. In February 2023, the MPSC issued an order approving the settlement agreement without modification.

## **KPCo Rate Matters (Applies to AEP)**

### ***CCR/ELG Compliance Plan Filings***

KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of December 31, 2022, the net book value of KPCo's share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $577 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.

In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.

In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. The WVPSC's order further states that unless KPCo pays for its share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the benefit of the capacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying for those costs.

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# OPCo Rate Matters (Applies to AEP and OPCo)

## *OVEC Cost Recovery Audits*

In December 2021, as part of OVEC cost recovery audits pending before the PUCO, intervenors filed positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO's April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact of these disputes; however, if any costs are disallowed or refunds are ordered it could reduce future net income and cash flows and impact financial condition. See 'OVEC' section of Note 17 for additional information on AEP and OPCo's investment in OVEC.

## *June 2022 Storm Costs*

In June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the transmission and distribution infrastructures. As of December 31, 2022, OPCo had incurred approximately $20 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a motion requesting the PUCO open a formal investigation into the power outages that occurred as a result of the June storms and determine if OPCo was negligent and liable to consumers for damages incurred as a result of the power outages. Separately, in July 2022, the PUCO directed its staff to conduct an after-action review to examine the circumstances of the event and OPCo's response to determine if OPCo adhered to the laws and rules in the state, followed its PUCO-approved emergency plan and responded appropriately to the event in an effort to mitigate the negative effects. In January 2023, the PUCO Staff issued a report which concluded OPCo was required to proactively shut down parts of its distribution system in order to avoid damages to the system and further outages and that OPCo adhered to its emergency plan. The report also directed OPCo to revise its vegetation programs around high voltage transmission lines and recommended that it make improvements to its emergency communications procedures. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

## *Ohio ESP Filings*

In January 2023, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments, proposed new riders and the continuation and modification of certain existing riders, including the DIR, effective June 2024 through May 2030. The proposal includes a return on common equity of 10.65% on capital costs for certain riders. If OPCo is ultimately not permitted to fully collect its ESP rates it could reduce future net income and cash flows and impact financial condition.

# PSO Rate Matters (Applies to AEP and PSO)

## *2022 Oklahoma Base Rate Case*

In November 2022, PSO filed a request with the OCC for a $173 million annual increase in rates based upon a 10.4% ROE with a capital structure of 45.4% debt and 54.6% common equity, net of existing rider revenues and certain incremental renewable facility benefits expected to be provided to customers through riders. The requested annual revenue increase includes a $47 million annual depreciation expense increase related to the accelerated depreciation recovery of the Northeastern Plant, Unit 3 through 2026, and a $16 million annual amortization expense increase to recover intangible plant over a 5-year useful life instead of a 10-year useful life. PSO's request also includes recovery of the 154 MW Rock Falls Wind Facility through base rates to aid PSO's near-term capacity needs and support compliance with SPP's 2023 increased capacity planning reserve margin requirements. In

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November 2022, PSO entered into an agreement to acquire the Rock Falls Wind Facility. In February 2023, the FERC approved PSO’s acquisition of the Rock Falls Wind Facility under Section 203 of the Federal Power Act. PSO expects to close on the acquisition and place the Rock Falls Wind Facility in-service during the first quarter of 2023. OCC approval is not a condition precedent to closing on the acquisition of the Rock Falls Wind Facility. In addition, PSO requested an annual formula based rate tariff, with an initial one-year pilot term. In the event the requested formula based rate tariff is denied, PSO has requested an expanded rider to recover certain distribution investments and related expenses as well as an expanded transmission cost recovery rider. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

### ***February 2021 Severe Winter Weather Impacts in SPP***

In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO’s extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.

In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.

### **SWEPCo Rate Matters (Applies to AEP and SWEPCo)**

#### ***2012 Texas Base Rate Case***

In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.

Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.

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In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decision. SWEPCo and the PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. In December 2022, SWEPCo and the PUCT filed requests for rehearing with the Texas Supreme Court. The Texas Supreme Court requested comments on rehearing by March 1, 2023. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.

Management does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of December 31, 2022. However, if SWEPCo is ultimately unable to recover AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $185 million related to revenues collected from February 2013 through December 2022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.

### *2016 Texas Base Rate Case*

In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in- service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.

As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors related to limiting SWEPCo’s recovery of AFUDC on Turk Plant and recovery of Welsh Plant, Unit 2. The appeal will move forward following the conclusion of the 2012 Texas Base Rate Case. If certain parts of the PUCT order are overturned, it could reduce future net income and cash flows and impact financial condition.

### *2020 Texas Base Rate Case*

In October 2020, SWEPCo filed a request with the PUCT for a $105 million annual increase in Texas base rates based upon a proposed 10.35% ROE. The request would move transmission and distribution interim revenues recovered through riders into base rates. Eliminating these riders would result in a net annual requested base rate increase of $90 million primarily due to increased investments. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.

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In January 2022, the PUCT issued a final order approving an annual revenue increase of $39 million based upon a 9.25% ROE. The order also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider to recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value to be recovered as a regulatory asset through 2046. As a result of the final order, SWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT challenging several errors in the order, which include challenges of the approved ROE, the denial of a reasonable return or carrying costs on the Dolet Hills Power Station and the calculation of the Texas jurisdictional share of the storm catastrophe reserve. 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.

### ***2020 Louisiana Base Rate Case***

In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. SWEPCo’s requested annual increase includes accelerated depreciation related to the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which were or are expected to be retired early. SWEPCo also included recovery of Welsh Plant, Unit 2 over the blended useful life of Welsh Plant, Units 1 and 3. SWEPCo subsequently revised the requested annual increase to $95 million to reflect removing hurricane storm restoration costs from the base case filing, to modify the proposed recovery of the Dolet Hills Power Station and revisions to various proposed amortizations. The hurricane costs have been requested in a separate storm filing. See “2021 Louisiana Storm Cost Filing” below for more information.

In January 2023, the LPSC approved a settlement which provides for an annual revenue increase of $27 million based upon a 9.5% ROE and includes: (a) a $21 million increase in base rates effective February 2023, (b) a $14 million rider to recover costs of the Dolet Hills Power Station and Pirkey Plant including a return, (c) an $8 million reduction in fuel rates, (d) an adoption of a 3-year formula rate term subject to an earnings band and (e) the recovery of certain incremental SPP charges net of associated revenue and the LA jurisdictional share of the return on and of projected transmission capital investment outside of the earnings band. The settlement agreement did not rule on the prudence of the early retirement of the Dolet Hills Power Station, which is being addressed in a separate proceeding.

The primary differences between SWEPCo’s requested annual rate increase and the agreed upon settlement increase are primarily due to: (a) a reduction in the requested ROE, (b) recovery of the Dolet Hills Power Station and Pirkey Plant over ten years in a separate rider mechanism as opposed to base rates with accelerated depreciation rates, (c) maintaining existing depreciation rates for Welsh Plant, Units 1 and 3 and (d) the severing of SWEPCo’s proposed adjustment to include a stand-alone NOLC deferred tax asset in rate base. In January 2023, a hearing was held related to the inclusion of a stand-alone NOLC deferred tax asset in rate base and an order from the LPSC is expected in 2023.

### ***2021 Arkansas Base Rate Case***

In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. In January 2022, SWEPCo filed testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates become effective in June 2022.

In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment

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resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.

### ***2021 Louisiana Storm Cost Filing***

In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected in 2023. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

### ***February 2021 Severe Winter Weather Impacts in SPP***

As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $329 million as of December 31, 2022, of which $75 million, $122 million and $132 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudence review and true-up.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.

If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

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# FERC Rate Matters

## *FERC SPP Transmission Formula Rate Challenge (Applies to AEP, AEPTCo, PSO and SWEPCo)*

In May 2021, certain joint customers submitted a formal challenge at the FERC related to the 2020 Annual Update of the 2019 SPP Transmission Formula Rates of the AEP transmission owning subsidiaries within SPP. In March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and SWEPCo. In November 2022, certain joint customers appealed the FERC decision to the U.S. Court of Appeals for the District of Columbia Circuit.

## *Independence Energy Connection Project (Applies to AEP)*

In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy has an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy appealed the PAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. In May 2022, the Pennsylvania state court issued an order affirming the PAPUC decision. The PAPUC decision remains subject to the jurisdiction and review of the United States District Court for the Middle District of Pennsylvania, which had stayed review of the PAPUC decision until the Pennsylvania state court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until 2023.

In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM continues to evaluate reliability and market efficiency in the area. As of December 31, 2022, AEP's share of IEC capital expenditures was approximately $87 million, located in Total Property, Plant and Equipment - Net on AEP's balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

## *FERC RTO Incentive Complaint (Applies to AEP, AEPTCo and OPCo)*

In February 2022, the Office of the Ohio Consumers' Counsel (OCC) filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners' respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the OCC's February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. In December 2022, the FERC issued an order removing the 50 basis point RTO incentive from OPCo and OHTCo transmission formula rates effective the date of the February 2022 complaint filing and directed OPCo and OHTCo to provide refunds, with interest, within sixty days of the date of its order. In January 2023, both AEPSC and the OCC filed requests for rehearing with the FERC. A FERC order on rehearing is expected in 2023. Based on management's preliminary estimates, the December 2022 FERC order is expected to reduce AEP's pretax income by approximately $20 million on an annual basis.

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### ***Request to Update AEGCo Depreciation Rates (Applies to AEP and I&M)***

In October 2022, AEP, on behalf of AEGCo, submitted proposed revisions to AEGCo’s depreciation rates for its 50% ownership interest in Rockport Plant, Unit 1 and Unit 2, reflected in AEGCo’s unit power agreement with I&M. The proposed depreciation rates for these assets reflect an estimated 2028 retirement date for the Rockport Plant. AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 1 were based upon a December 31, 2028 estimated retirement date while AEGCo’s previous FERC-approved depreciation rates for Rockport Plant, Unit 2 leasehold improvements were based upon a December 31, 2022 estimated retirement date in conjunction with the termination of the Rockport Plant, Unit 2 lease.

In December 2022, the FERC issued an order approving the proposed AEGCo Rockport depreciation rates effective January 1, 2023, subject to further review and a potential refund. The FERC established a separate proceeding to review: (a) AEGCo’s acquisition value for the Rockport Plant, Unit 2 base generating asset (original cost and accumulated depreciation), (b) the appropriateness of including future capital additions as stated components in proposed depreciation rates, in light of the UPA’s formula rate mechanism, (c) the appropriateness of applying two different depreciation rates to a single asset common to both units and (d) the accounting and regulatory treatment of Rockport Plant, Unit 2 costs of removal and related AROs. It is expected that the FERC will issue an order on this review in the second half of 2023. This FERC review and subsequent order on these issues could reduce future net income and cash flows and impact financial conditions.

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## **5. EFFECTS OF REGULATION**

The disclosures in this note apply to all Registrants unless indicated otherwise.

### ***Coal-Fired Generation Plants (Applies to AEP, PSO and SWEPCo)***

Compliance with extensive environmental regulations requires significant capital investment in environmental monitoring, installation of pollution control equipment, emission fees, disposal costs and permits. Management continuously evaluates cost estimates of complying with these regulations which has resulted in, and in the future may result in, a decision to retire coal-fired generating facilities earlier than their currently estimated useful lives.

Management is seeking or will seek regulatory recovery, as necessary, for any net book value remaining when the plants are retired. To the extent the net book value of these generation assets is not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

#### *Regulated Generating Units that have been Retired*

##### **SWEPCo**

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section of Note 4 for additional information. As part of the 2019 Arkansas Base Rate Case, SWEPCo received approval from the APSC to recover the Arkansas jurisdictional share of Welsh Plant, Unit 2. In December 2020, SWEPCo filed a request with the LPSC to recover the Louisiana jurisdictional share of Welsh Plant, Unit 2. In January 2023, the LPSC approved a settlement agreement which provided recovery of Welsh Plant, Unit 2 as requested. See “2020 Louisiana Base Rate Case” section of Note 4 for additional information.

In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station through 2027, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudence of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. As part of the 2020 Louisiana Base Rate Case, the LPSC authorized the recovery of SWEPCo’s Louisiana share of the Dolet Hills Power Station, through a separate rider, through 2032, but did not rule on the prudence of the early retirement of the plant, which is being addressed in a separate proceeding. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections of Note 4 for additional information.

#### *Regulated Generating Units to be Retired*

##### **PSO**

In 2014, PSO received final approval from the Federal EPA to close Northeastern Plant, Unit 3, in 2026. The plant was originally scheduled to close in 2040. As a result of the early retirement date, PSO revised the useful life of Northeastern Plant, Unit 3, to the projected retirement date of 2026 and the incremental depreciation is being deferred as a regulatory asset. As part of the 2021 Oklahoma Base Rate Case, PSO will continue to recover Northeastern Plant, Unit 3 through 2040.

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