AEP - American Electric Power Company Inc.

07/22/2021 | Press release | Distributed by Public on 07/22/2021 05:44

Quarterly Report (SEC Filing - 10-Q)






UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2021
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission Registrants; I.R.S. Employer
File Number Address and Telephone Number States of Incorporation Identification Nos.
1-3525 AMERICAN ELECTRIC POWER CO INC. New York 13-4922640
333-221643 AEP TEXAS INC. Delaware 51-0007707
333-217143 AEP TRANSMISSION COMPANY, LLC Delaware 46-1125168
1-3457 APPALACHIAN POWER COMPANY Virginia 54-0124790
1-3570 INDIANA MICHIGAN POWER COMPANY Indiana 35-0410455
1-6543 OHIO POWER COMPANY Ohio 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA Oklahoma 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY Delaware 72-0323455
1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 716-1000
Securities registered pursuant to Section 12(b) of the Act:
Registrant Title of each class Trading Symbol Name of Each Exchange on Which Registered
American Electric Power Company Inc. Common Stock, $6.50 par value AEP The NASDAQ Stock Market LLC
American Electric Power Company Inc. 6.125% Corporate Units AEPPL The NASDAQ Stock Market LLC
American Electric Power Company Inc. 6.125% Corporate Units AEPPZ The NASDAQ Stock Market LLC
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes x No
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
Yes x No
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of 'large accelerated filer,' 'accelerated filer,' 'smaller reporting company,' and 'emerging growth company' in Rule 12b-2 of the Exchange Act.
Large Accelerated filer x Accelerated filer Non-accelerated filer
Smaller reporting company Emerging growth company
Indicate by check mark whether AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies, or emerging growth companies. See the definitions of 'large accelerated filer,' 'accelerated filer,' 'smaller reporting company,' and 'emerging growth company' in Rule 12b-2 of the Exchange Act.
Large Accelerated filer Accelerated filer Non-accelerated filer x
Smaller reporting company Emerging growth company
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). Yes No x
AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.





Number of shares
of common stock
outstanding of the
Registrants as of
July 22, 2021
American Electric Power Company, Inc. 500,251,339
($6.50 par value)
AEP Texas Inc. 100
($0.01 par value)
AEP Transmission Company, LLC (a) NA
Appalachian Power Company 13,499,500
(no par value)
Indiana Michigan Power Company 1,400,000
(no par value)
Ohio Power Company 27,952,473
(no par value)
Public Service Company of Oklahoma 9,013,000
($15 par value)
Southwestern Electric Power Company 3,680
($18 par value)

(a)100% interest is held by AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of American Electric Power Company, Inc.
NA Not applicable.





AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF QUARTERLY REPORTS ON FORM 10-Q
June 30, 2021
Page
Number
Glossary of Terms
i
Forward-Looking Information
v
Part I. FINANCIAL INFORMATION
Items 1, 2, 3 and 4 - Financial Statements, Management's Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Controls and Procedures:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Discussion and Analysis of Financial Condition and Results of Operations
1
Condensed Consolidated Financial Statements
51
AEP Texas Inc. and Subsidiaries:
Management's Narrative Discussion and Analysis of Results of Operations
58
Condensed Consolidated Financial Statements
63
AEP Transmission Company, LLC and Subsidiaries:
Management's Narrative Discussion and Analysis of Results of Operations
70
Condensed Consolidated Financial Statements
73
Appalachian Power Company and Subsidiaries:
Management's Narrative Discussion and Analysis of Results of Operations
79
Condensed Consolidated Financial Statements
83
Indiana Michigan Power Company and Subsidiaries:
Management's Narrative Discussion and Analysis of Results of Operations
90
Condensed Consolidated Financial Statements
95
Ohio Power Company and Subsidiaries:
Management's Narrative Discussion and Analysis of Results of Operations
102
Condensed Consolidated Financial Statements
107
Public Service Company of Oklahoma:
Management's Narrative Discussion and Analysis of Results of Operations
114
Condensed Financial Statements
119
Southwestern Electric Power Company Consolidated:
Management's Narrative Discussion and Analysis of Results of Operations
126
Condensed Consolidated Financial Statements
131
Index of Condensed Notes to Condensed Financial Statements of Registrants
137
Controls and Procedures
236





Part II. OTHER INFORMATION
Item 1. Legal Proceedings
237
Item 1A. Risk Factors
237
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
237
Item 3. Defaults Upon Senior Securities
237
Item 4. Mine Safety Disclosures
237
Item 5. Other Information
237
Item 6. Exhibits
238
SIGNATURE
239
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Texas Inc., AEP Transmission Company, LLC, Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.





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 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.
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.
AFUDC
Allowance for Equity Funds Used During Construction.
AGR
AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing segment.
AMI
Advanced Metering Infrastructure.
AMR Automated Meter Reading.
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 Expanded Net Energy Cost deferral balance.
APSC
Arkansas Public Service Commission.
ARO
Asset Retirement Obligations.
ASU
Accounting Standards Update.
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.
CO2
Carbon dioxide and other greenhouse gases.
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, 2,288 MW nuclear plant owned by I&M.
i




Term
Meaning
COVID-19
Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CSAPR
Cross-State Air Pollution Rule.
CWIP
Construction Work in Progress.
DCC Fuel
DCC Fuel X, DCC Fuel XI, DCC Fuel XII, DCC Fuel XIII, DCC Fuel XIV, DCC Fuel XV and DCC Fuel XVI, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. DHLC is a non-consolidated VIE of SWEPCo.
DIR
Distribution Investment Rider.
EIS
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated VIE of AEP.
ELG Effluent Limitation Guidelines.
Energy Supply
AEP Energy Supply LLC, a nonregulated holding company for AEP's competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
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.
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.
I&M
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS
Internal Revenue Service.
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.
KWh
Kilowatt-hour.
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.
ii




Term
Meaning
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.
Nonutility Money Pool
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
North Central Wind Energy Facilities
A joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,485 MWs of wind generation.
NOx
Nitrogen oxide.
NSR
New Source Review.
OCC
Corporation Commission of the State of Oklahoma.
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.
OPCo
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
Other Postretirement Benefits.
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.
PJM
Pennsylvania - New Jersey - Maryland regional transmission organization.
PM
Particulate Matter.
PPA
Purchase Power and Sale Agreement.
PSO
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTC
Production Tax Credits.
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 owned by AGR.
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.
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, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
iii




Term
Meaning
ROE
Return on Equity.
RPM
Reliability Pricing Model.
RTO
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
Sabine Mining Company, a lignite mining company that is a consolidated VIE for AEP and SWEPCo.
SEC U.S. Securities and Exchange Commission.
Sempra Renewables LLC
Sempra Renewables LLC, acquired in April 2019, consists of 724 MWs of wind generation and battery assets in the United States.
SIP
State Implementation Plan.
SNF
Spent Nuclear Fuel.
SO2
Sulfur dioxide.
SPP
Southwest Power Pool regional transmission organization.
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.
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.
Transition Funding
AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated VIE formed for the purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. In July 2020, the final AEP Texas Central Transition Funding II securitization bond matured.
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 999 MWs of wind generation in Oklahoma.
Turk Plant
John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
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.
WPCo
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
Public Service Commission of West Virginia.
iv




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 'Part I - Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations' of this quarterly report, 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, including COVID-19, and any associated disruption of AEP's business operations due to impacts on economic or market conditions, electricity usage, employees, customers, service providers, vendors and suppliers.
Inflationary or deflationary interest rate trends.
Volatility in the financial markets, 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 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 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 and 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.
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including coal ash and nuclear fuel.
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.
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.
Changes in utility regulation and the allocation of costs within RTOs including ERCOT, PJM and SPP.
v




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, 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 the 2020 Annual Report and in Part II of this report.

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






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

EXECUTIVE OVERVIEW

Impacts of Severe Winter Weather

In February 2021, severe winter weather impacted the service territories of APCo, KPCo, PSO and SWEPCo resulting in power outages, extensive damage to infrastructure and disruptions to SPP market conditions. Impacts of the severe winter weather are included below. See Note 4 - Rate Matters for additional information.

Storm Restoration Costs

The impact of the severe winter weather resulted in power outages and extensive damage to transmission and distribution infrastructures across the service territories of APCo, KPCo and SWEPCo. As of June 30, 2021, an estimated $65 million of capital expenditures and $144 million of restoration expenses have been incurred related to the severe winter weather. Approximately $138 million of the expenses represent incremental restoration expenses and have been deferred as regulatory assets. The KPSC and LPSC issued orders authorizing the deferral of incremental restoration expenses as regulatory assets. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo and SWEPCo are expected to seek recovery in separate filings. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Impacts in SPP

The severe winter weather also 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.

Retail Customers

As of June 30, 2021, PSO and SWEPCo have deferred regulatory assets of $669 million and $453 million, respectively, relating to natural gas expenses and purchases of electricity incurred from February 9, 2021, to February 20, 2021, as a result of severe winter weather. SWEPCo's deferred regulatory asset consists of $116 million, $161 million and $176 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively. PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

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. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a pretax rate of return of 1.65%. In July 2021, the APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. Once testimony concludes, a hearing will be scheduled. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

1




In March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery period. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including carrying costs 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 to securitize the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization.

SWEPCo expects to make a filing with the PUCT in the third quarter of 2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.

Wholesale Customers

During the first quarter of 2021, SWEPCo billed wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of June 30, 2021, $63 million of accounts receivable from wholesale customers are outstanding. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

PSO and SWEPCo evaluated financing alternatives to address the timing difference between the payment of the estimated natural gas expenses and purchases of electricity to suppliers and subsequent recovery from customers. In March 2021, PSO drew $100 million on its revolving credit facility and SWEPCo issued $500 million of Senior Unsecured Notes. In March 2021, Parent entered into a $500 million 364-day Term Loan and borrowed the full amount. The proceeds from this loan were used to help fund capital contributions to PSO and SWEPCo totaling $425 million and $100 million, respectively. In April 2021, PSO received an additional capital contribution from Parent of $125 million to further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP's results of operations for the three and six months ended June 30, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

COVID-19

In 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in AEP's service territory and resulted in reduced demand for energy, particularly from commercial and industrial customers. In 2021, weather-normalized customer demand has improved from the pandemic levels experienced in 2020. Management expects continued improvement during the remainder of 2021 as additional vaccinations occur and economic activity improves.

During 2020, AEP's electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP's state regulators also imposed temporary moratoria on customary disconnection practices. As of June 30, 2021, AEP's electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2021.
2






AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of June 30, 2021, AEP currently does not expect accounts receivable aging to have a material adverse impact on the Registrants' allowance for uncollectible accounts based on considerations of the COVID-19 impacts and past trends during times of economic instability. Management continues to monitor developments that could have an impact on customer collections.

The Registrants continue to take steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19. As of June 30, 2021, there has been no material adverse impact to the Registrants' business operations and customer service as a result of the current remote work model. In the second quarter of 2021, management announced a Future of Work model designating employees as: (a) On-Site employees, (b) Hybrid employees and (c) Remote employees. Management currently expects to begin transitioning On-Site employees back to their AEP workplace and Hybrid employees with set schedules back to their AEP workplace in August 2021. Remote employees will begin transitioning back to their AEP workplace in September 2021 on an as-needed basis. Management will continue to review and modify plans as conditions change.

In 2021, the Registrants have experienced certain supply chain disruptions driven by several factors including staffing and travel issues caused by the COVID-19 pandemic, the economic recovery from the pandemic, labor shortages 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. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions. However, a prolonged continuation or a future increase in the severity of supply chain disruptions could impact the cost of certain goods and services and extend lead times which could reduce future net income and cash flows and impact financial condition.

Customer Demand

AEP's weather-normalized retail sales volumes for the second quarter of 2021 increased by 6.3% from the second quarter of 2020. Weather-normalized residential sales decreased by 3.1% in the second quarter of 2021 from the second quarter of 2020. AEP's second quarter 2021 industrial sales volumes increased by 12.8% compared to the second quarter of 2020. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 10% in the second quarter of 2021 from the second quarter of 2020.

AEP's weather-normalized retail sales volumes for the six months ended June 30, 2021 increased by 1.9% compared to the six months ended June 30, 2020. Weather-normalized residential sales decreased by 0.5% for the six months ended June 30, 2021 compared to the six months ended June 30, 2020. AEP's industrial sales volumes for the six months ended June 30, 2021 increased by 2.8% compared to the six months ended June 30, 2020. The recovery in industrial sales volumes was spread across many industries. Weather-normalized commercial sales increased 3.9% for the six months ended June 30, 2021 compared to the six months ended June 30, 2020.

The increase in industrial and commercial sales volumes is primarily the result of the COVID-19 pandemic's impact on the second quarter of 2020 when public health restrictions significantly disrupted economic activity and demand for energy in AEP's service territory. Similarly, the decline in weather-normalized residential sales volumes is driven by the cessation of stay at home restrictions that were in place in 2020 and the gradual return of customers to the workplace.


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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 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo's closed coal-fired generation assets, (b) the Virginia SCC's use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo's 2017 - 2019 earnings test and (c) the reasonableness and prudency of APCo's investments in AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo's going-forward rates and (b) the Virginia SCC's decision to deny APCo tariff changes that align rates with underlying costs. For APCo's going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo's current rates will allow it to earn a fair return. If the Virginia SCC's order did conclude on APCo's ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor's recommendation that APCo's AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. APCo expects to submit its brief before the Virginia Supreme Court in the third quarter of 2021.

In April 2021, and in conjunction with APCo's November 2020 and March 2021 appeals with the Virginia Supreme Court, APCo filed a petition for interim rates with the Virginia Supreme Court (subject to refund with interest and supported by a bond issuance) requesting a $40 million increase in annual APCo Virginia base rates. APCo submitted this filing based on Virginia law that allows the Virginia Supreme Court to authorize interim rates until the final disposition on APCo's appeals. APCo also requested an expedited schedule from the Virginia Supreme Court on APCo's appeals. In May 2021, the Virginia Supreme Court denied APCo's petition for an interim rate increase and denied the request for an expedited schedule on APCo's appeals.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo's request for proper treatment of the closed coal-fired plant assets in APCo's 2017-2019 triennial period, reducing APCo's earnings below the bottom of its authorized ROE band. If APCo's appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo's 2017-2019 authorized ROE band.
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2020 Ohio Base Rate Case- In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO based upon an annual revenue decrease of $68 million and an ROE of 9.7%. The difference between OPCo's requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. In addition, the joint stipulation and settlement agreement includes an increased fixed monthly residential customer charge, the discontinuation of rate decoupling and the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. A hearing took place with the PUCO in May 2021 and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected by the end of 2021.

Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo's service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $83 million ($81 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $30 million, all of which is related to the Louisiana jurisdiction. Management expects to request recovery of these storm costs in a filing inclusive of SWEPCo's various other storm costs.

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. 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. No parties filed a motion for rehearing with the Texas Supreme Court. As of June 30, 2021, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. SWEPCo's Texas jurisdictional share of the Turk Plant investment is approximately 33%.

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 phased out current energy efficiency programs as of December 31, 2020, including OPCo's shared savings revenues of $26 million annually and renewable mandates after 2026. HB 6 also provided for the recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for recovery of OVEC costs through 2030 which will be allocated to all electric distribution utilities 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. In August 2020, an AEP shareholder filed a putative class action lawsuit against AEP and certain of its officers for alleged violations of securities laws in connection with HB 6. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, and under the Court's briefing schedule the motion will be fully briefed by July 26, 2021. In addition, four AEP shareholders have filed derivative actions purporting
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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, rescinded 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 after 90 days 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 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 securities class action or the derivative actions, it could reduce future net income and cash flows and impact financial condition.

In December 2020, APCo and WPCo filed a proposal with the WVPSC to implement an investment tracker surcharge mechanism for recovering costs associated with capital investment made between base rate cases. The initial filing requests a total annual increase of $50 million ($41 million related to APCo), which represents recovery of costs associated with infrastructure investments made over an approximate three-year period since the companies' last base rate case filing in 2018. The filing also proposes that APCo and WPCo could submit annual filings with requested increases capped to a percentage of total retail revenues (3.5% in the first year and 3% in subsequent filings with an overall cap of 9.5%). If a future base rate case is filed, the surcharge would reset to zero on implementation of the new rates.

In July 2021, the WVPSC issued an order approving the investment tracker mechanism with an initial annual revenue requirement of $44 million ($35 million related to APCo) effective September 2021 based on a 9.25% ROE. Under the conditions of the order, APCo and WPCo would not be permitted to file a base rate case before June 30, 2024. The order also allows APCo and WPCo to request future year investment tracker increases for assets placed in service during the most recent 12-month period ending September 30th, subject to an annual three percent rider increase cap on base year total retail revenues. APCo and WPCo filed a petition for reconsideration with the WVPSC to reconsider and modify certain parts of the order, including the condition that APCo and WPCo will not file a base rate case before June 30, 2024. The companies request certain exceptions to be recognized that allow for base rate case filings in certain circumstances.

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 is subject to a 60 day comment period followed by a 30 day period for reply comments. A final rule could be issued in the fourth quarter of 2021.

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%).

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 impact on AEP's transmission owning subsidiaries whose RTO membership is not voluntary, including OPCo and AEP Ohio Transmission Company.
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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 $55 million to $70 million on an annual basis.

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' pending base rate case proceedings in 2021. See Note 4 - Rate Matters for additional information.

Completed Base Rate Case Proceedings

Approved Revenue Approved New Rates
Company Jurisdiction Requirement Increase ROE Effective
(in millions)
KPCo Kentucky $ 52.7 (a) 9.3% January 2021

(a)See '2020 Kentucky Base Rate Case' section of Note 4 Rate Matters in the 2020 Annual Report for additional information.

Pending Base Rate Case Proceedings
Commission Staff/
Filing Requested Revenue Requested Intervenor Range of
Company Jurisdiction Date Requirement Increase ROE Recommended ROE
(in millions)
OPCo Ohio June 2020 $ 42.3 10.15% 8.76%-9.78% (a)
SWEPCo Texas October 2020 105.0 (b) 10.35% 9%-9.22% (c)
SWEPCo Louisiana December 2020 114.0 10.35% 9.1%-9.8% (d)
PSO Oklahoma April 2021 172.4 10% (e)
I&M Indiana July 2021 104.0 (f) 10% (g)

(a)In March, 2021 a joint stipulation and settlement agreement was filed with the PUCO which included a $68 million decrease in base rates based upon an ROE of 9.7%.
(b)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.
(c)Staff and intervenors recommended base rate increases ranged from $20 million to $70 million.
(d)Staff recommended a base rate increase of $6 million.
(e)Intervenor testimony is expected in the third quarter of 2021.
(f)Proposed to be phased-in with a $73 million annual increase effective May 2022 and the remaining $31 million annual increase effective January 2023.
(g)Intervenor testimony is expected in the fourth quarter of 2021.
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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

AEP continues to develop its renewable portfolio within the Generation & Marketing segment. Activities include 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 develops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.

As of June 30, 2021, subsidiaries within AEP's Generation & Marketing segment had approximately 1,633 MWs of contracted renewable generation projects in-service. In addition, as of June 30, 2021, these subsidiaries had approximately 155 MWs of renewable generation projects under construction with total estimated capital costs of $221 million related to these projects.

Regulated Renewable Generation Facilities

In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSC to acquire the North Central Wind Energy Facilities, comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. Both the APSC and LPSC approved the flex-up option, agreeing to acquire the Texas portion, which the PUCT denied. PSO will own 45.5% and SWEPCo will own 54.5% of the project, which will cost approximately $2 billion.

In June 2021, the IRS issued a notice extending the 'Continuity Safe Harbor' deadlines for qualifying renewable energy projects. Under the June 2021 IRS notice, the Continuity Safe Harbor for qualifying renewable energy projects that began construction in calendar years 2016 through 2019 is extended to six years. Additionally, the Continuity Safe Harbor is extended to five years for qualifying projects that began construction in calendar year 2020. Provided that each facility does satisfy the Continuity Safe Harbor, under the current IRS guidance, the Sundance wind facility will qualify for 100% of the federal PTC, and the Maverick and Traverse wind facilities will qualify for 80% of the federal PTC.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. The total investment in Sundance is estimated to be $291 million inclusive of previously capitalized pre-construction costs. The Maverick wind facility is targeted to be acquired and placed in-service in December 2021 and the Traverse wind facility is targeted to be acquired and placed in-service between December 2021 and April 2022. See Note 6 - Acquisitions for additional information.

In June 2021, SWEPCo issued requests for proposals to acquire up to 3,000 MWs of wind and 300 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.

Strategic Evaluation of KPCo and AEP Kentucky Transmission Company, Inc. (KTCo)

AEP has initiated a strategic evaluation for its ownership in KPCo, a wholly-owned regulated generation, transmission and distribution utility with approximately 166,000 retail customers in eastern Kentucky and KTCo, an AEPTCo wholly-owned regulated transmission only utility. Potential alternatives may include continued ownership or a sale of KPCo and KTCo. Management is currently evaluating the potential alternatives and expects a decision will be made during 2021. As of June 30, 2021, KPCo has total assets of approximately $2.8 billion and total equity of approximately $847 million and KTCo has total assets of approximately $157 million and total equity of approximately $73 million.
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Racine

In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of June 30, 2021, the net book value of Racine was $45 million. The sale of Racine requires approval from the FERC and the U.S. Army Corps of Engineers. The sale is expected to close in the third quarter of 2021 and result in an immaterial gain. Racine was not presented as Held for Sale on AEP's balance sheets due to immateriality.

Dolet Hills Power Station and Related Fuel Operations

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC's and Oxbow's assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. In addition, management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through base rates. SWEPCo's share of the net investment in the Dolet Hills Power Station is $147 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo's fuel inventory and unbilled fuel costs from mining related activities were $119 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See '2020 Texas Fuel Reconciliation' section of Note 4 for additional information.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date.

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

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


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Pirkey Power Plant and Related Fuel Operations

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. SWEPCo's share of the net investment in the Pirkey Power Plant is $206 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an 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 $148 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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 5 - Commitments, Guarantees and Contingencies for additional information.

Rockport Plant Litigation

In 2013, the Wilmington Trust Company filed a complaint 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 seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs' claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court's dismissal of the owners' breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court's dismissal of the breach of contract claims and remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners' unopposed motion to stay the lease litigation to afford time for resolution of AEP's motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court's stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP's memorandum in
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opposition to plaintiffs' motion for partial summary judgment was filed in October 2020. At the parties' request, the district court stayed the case until April 19, 2021 to provide the parties an opportunity to resolve the case. See 'Obligations under the New Source Review Litigation Consent Decree' section below for additional information.

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 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, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. As a result, in May 2021, at the parties request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The agreement is subject to customary closing conditions, including regulatory approvals, and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. Management believes its financial statements appropriately reflect the expected resolution of the pending litigation.

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

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. 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 Claimants have asserted claims 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) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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, the Company, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do 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 United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleges 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 seeks monetary damages, among other forms of relief. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, and under the Court's briefing schedule the motion will be fully briefed by July 26, 2021. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United States 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
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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 first three derivative actions have been stayed pending the resolution of the motion to dismiss the securities litigation. The fourth has been stayed until such time as the court determines to lift the stay. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

On March 1, 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, the Company commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has agreed that AEP and the AEP Board may defer consideration of the litigation demand until the resolution of the motion to dismiss the securities litigation. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In May 2021, AEP received a subpoena from the SEC's Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP's financial processes and controls. AEP is cooperating fully with the SEC's subpoena. Although we cannot predict the outcome of the SEC's investigation, we do not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.

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. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

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 June 30, 2021, the AEP System owned generating capacity of approximately 24,700 MWs, of which approximately 12,100 MWs were coal-fired. Management continues to 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 $350 million to $700 million through 2027.

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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 and (g) 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 SO2and NOXemissions from the AEP System and various mitigation projects. The consent decree has been modified six times, for various reasons, most recently in 2020. 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 any 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. Most recently, the Biden administration has indicated that it is likely to revisit the NAAQS for ozone and PM, which were left unchanged by the prior administration following its review. Management cannot currently predict if any changes to either standard are likely 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 postpones 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.

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 NOXregional haze obligations for electric
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generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2emissions 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 contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS. CSAPR relies on SO2and NOXallowances and individual state budgets to compel further emission reductions from electric utility generating units. Interstate trading of allowances is allowed on a restricted sub-regional basis.

In January 2021, the Federal EPA finalized a revised CSAPR rule, which substantially reduces the ozone season NOXbudgets in 2021-2024. Management 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.

Climate Change, CO2Regulation 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 D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. 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. Management continues to actively monitor these rulemaking activities.

While no federal regulatory requirements to reduce CO2emissions are in place, AEP has taken action to reduce and offset CO2emissions from its generating fleet. AEP expects CO2emissions 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, 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 February 2021, AEP announced new intermediate and long-term CO2emission 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. The intermediate goal is an 80% reduction from 2000 CO2emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2emissions from AEP generating facilities by 2050. AEP's total estimated CO2emissions in 2020 were approximately 44 million metric tons, a 73% reduction from AEP's 2000 CO2emissions. AEP has made significant progress in reducing CO2emissions 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.

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Coal Combustion Residual 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 August 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.

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 and Unit Generating
Capacity
Net Book Value (a) Projected
Retirement Date
(in MWs) (in millions)
AEGCo Rockport Plant, Unit 1 655 $ 237.1 2028
APCo Amos 2,930 2,128.5 2040
APCo Mountaineer 1,320 966.4 2040
I&M Rockport Plant, Unit 1 655 541.6 (b) 2028
KPCo Mitchell Plant 780 591.9 2040
SWEPCo Flint Creek Plant 258 271.9 2038
WPCo Mitchell Plant 780 594.4 2040

(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $181 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 December 2020, APCo filed requests with the Virginia SCC and WVPSC to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for the Amos and Mountaineer plants. In July 2021, a Virginia Senior Hearing Examiner recommended that the Virginia SCC deny, at this time, APCo's request for approval of the ELG investments at the Amos and Mountaineer Plants. The judge also recommended that if the Virginia SCC ultimately does not grant APCo approval of the ELG investments, the Virginia SCC should delay consideration of the reasonableness and prudency of previously incurred ELG costs until a future case. Intervenors in Virginia and West Virginia along with the Virginia Senior Hearing Examiner recommended that only the CCR-related investments be constructed at Amos and Mountaineer, which could cause APCo to close these generating facilities at the end of 2028. If any of APCo's CCR/ELG costs are not approved for recovery, it would reduce future net income and cash flows and impact financial condition. See 'APCo and WPCo Rate Matters' section of Note 4 for additional information.

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 through 2040. 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 May 2021, intervenors in Kentucky and West Virginia submitted testimony with recommendations that only the CCR-related investments be constructed at the Mitchell Plant. In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. As of June 30, 2021, the total of the Mitchell Plant CCR and ELG investment balances in CWIP, was $2 million and $4 million, respectively, split equally between KPCo and WPCo. If any of the CCR and ELG compliance plan costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without
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commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition. See 'KPCo Rate Matters' section of Note 4 for additional information.

The second option is a retirement option, which provides a generating facility an extended operating time without developing alternative CCR disposal. Under the retirement option, a generating facility would have until October 17, 2023 to cease operation 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 Power Plant and cease using coal at the Welsh Plant:
Company Plant Name and Unit Generating
Capacity
Net Investment (a) Accelerated Depreciation Regulatory Asset Projected
Retirement Date
(in MWs) (in millions)
SWEPCo Pirkey Power Plant 580 $ 157.1 $ 49.4 2023 (b)
SWEPCo Welsh Plants, Units 1 and 3 1,053 511.2 24.9 2028 (c)(d)

(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and 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.

AEP may incur significant costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions. Under the retirement option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiring 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 retiring plants in a timely manner, it would reduce future net income and cash flows and impact financial condition.

Closure and post-closure costs have been included in ARO in accordance with the requirements in the final 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, which could include costs to remove ash from some unlined units.

If removal of ash is required without providing similar assurances of cost recovery in regulated jurisdictions, it would impose significant additional operating costs on AEP, which could lead to increased financing costs and liquidity needs. Other units in Virginia, Ohio, West Virginia and Kentucky have already been closed in place in accordance with state law programs. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.

Clean Water Act Regulations

The Federal EPA's ELG rule for generating facilities establishes limits on 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 recent 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. Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment. We continue to work with state agencies to finalize permit terms and conditions.

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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 costs 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 Unit 2, Oklaunion Power Station, Dolet Hills Power Station and Northeastern Plant Unit 3.

The table below summarizes the net book value, as of June 30, 2021, of generating facilities retired or planned for early retirement:
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 $ 183.2 $ 119.2 2026 (c) $ 14.9
PSO Oklaunion Power Station - 33.5 2020 (d) 1.9
SWEPCo Dolet Hills Power Station 27.3 114.3 2021 (e) 7.8
SWEPCo Pirkey Power Plant 138.5 49.4 2023 (f) 13.6
SWEPCo Welsh Plant, Units 1 and 3 500.6 24.9 2028 (g) (h) 33.2
SWEPCo Welsh Plant, Unit 2 - 35.2 2016 (i) -

(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)Oklaunion Power Station is currently being recovered through 2046.
(e)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(f)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(h)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.
(i)Welsh Plant, Unit 2 is being recovered 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 are 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 and Amortization of Generation Deferrals 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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The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions)
Vertically Integrated Utilities $ 228.2 $ 255.9 $ 498.6 $ 501.2
Transmission and Distribution Utilities 153.7 139.5 268.1 255.7
AEP Transmission Holdco 168.7 91.5 340.7 232.1
Generation & Marketing 52.4 65.9 89.0 94.3
Corporate and Other (24.8) (32.0) (43.2) (67.3)
Earnings Attributable to AEP Common Shareholders
$ 578.2 $ 520.8 $ 1,153.2 $ 1,016.0

AEP CONSOLIDATED

Second Quarter of 2021 Compared to Second Quarter of 2020

Earnings Attributable to AEP Common Shareholders increased from $521 million in 2020 to $578 million in 2021 primarily due to:

Favorable rate proceedings in AEP's various jurisdictions.
An increase in transmission investment, which resulted in higher revenues and income.
Unrealized gains on AEP's investment in ChargePoint.

These increases were partially offset by:

An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in the second quarter of 2020.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders increased from $1,016 million in 2020 to $1,153 million in 2021 primarily due to:

Favorable rate proceedings in AEP's various jurisdictions.
An increase in weather-related usage.
An increase in transmission investment, which resulted in higher revenues and income.
Unrealized gains on AEP's investment in ChargePoint.

These increases were partially offset by:

An increase in Other Operation and Maintenance expenses driven by the COVID-19 pandemic which resulted in lower expenses in 2020.
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VERTICALLY INTEGRATED UTILITIES
Three Months Ended Six Months Ended
June 30, June 30,
Vertically Integrated Utilities 2021 2020 2021 2020
(in millions)
Revenues $ 2,260.6 $ 2,092.0 $ 4,797.9 $ 4,318.7
Fuel and Purchased Electricity 650.4 582.1 1,509.4 1,253.3
Gross Margin 1,610.2 1,509.9 3,288.5 3,065.4
Other Operation and Maintenance 703.5 624.6 1,443.7 1,315.9
Depreciation and Amortization 433.8 393.3 865.9 775.0
Taxes Other Than Income Taxes 128.0 117.5 251.5 234.6
Operating Income 344.9 374.5 727.4 739.9
Other Income 5.1 1.4 5.8 3.0
Allowance for Equity Funds Used During Construction
10.8 9.0 20.7 17.2
Non-Service Cost Components of Net Periodic Benefit Cost 17.0 17.1 34.0 34.0
Interest Expense (141.6) (141.8) (281.2) (286.3)
Income Before Income Tax Expense and Equity Earnings 236.2 260.2 506.7 507.8
Income Tax Expense 8.2 4.6 8.0 6.7
Equity Earnings of Unconsolidated Subsidiary 0.8 0.7 1.5 1.5
Net Income 228.8 256.3 500.2 502.6
Net Income Attributable to Noncontrolling Interests 0.6 0.4 1.6 1.4
Earnings Attributable to AEP Common Shareholders $ 228.2 $ 255.9 $ 498.6 $ 501.2

Summary of KWh Energy Sales for Vertically Integrated Utilities
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 6,525 6,976 16,006 15,238
Commercial 5,670 5,150 10,928 10,516
Industrial 8,611 7,699 16,313 16,174
Miscellaneous 549 511 1,068 1,041
Total Retail 21,355 20,336 44,315 42,969
Wholesale (a) 4,487 4,924 9,129 8,542
Total KWhs 25,842 25,260 53,444 51,511

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



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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
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Eastern Region
Actual -Heating (a)
170 212 1,709 1,453
Normal -Heating (b)
138 137 1,738 1,748
Actual -Cooling (c)
359 324 362 337
Normal -Cooling (b)
339 337 343 342
Western Region
Actual - Heating (a)
35 49 993 698
Normal -Heating (b)
34 34 900 901
Actual -Cooling (c)
652 673 678 724
Normal -Cooling (b)
699 700 727 728

(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.

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Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Second Quarter of 2020 $ 255.9
Changes in Gross Margin:
Retail Margins 96.4
Margins from Off-system Sales 5.6
Transmission Revenues 0.9
Other Revenues (2.6)
Total Change in Gross Margin 100.3
Changes in Expenses and Other:
Other Operation and Maintenance (78.9)
Depreciation and Amortization (40.5)
Taxes Other Than Income Taxes (10.5)
Other Income 3.7
Allowance for Equity Funds Used During Construction 1.8
Non-Service Cost Components of Net Periodic Pension Cost (0.1)
Interest Expense 0.2
Total Change in Expenses and Other (124.3)
Income Tax Expense (3.6)
Equity Earnings of Unconsolidated Subsidiary 0.1
Net Income Attributable to Noncontrolling Interests (0.2)
Second Quarter of 2021 $ 228.2

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 Marginsincreased $96 million primarily due to the following:
A $36 million increase at I&M due to wholesale true-up, increase in rider revenues and the Indiana base rate case. This increase was partially offset in other expense items below.
A $17 million increase in revenue from rate riders at PSO. This increase was partially offset in other expense items below.
A $12 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
A $9 million increase at APCo and WPCo due to rider revenue primarily in West Virginia. This increase was partially offset in other expense items below.
An $8 million increase in weather-normalized retail margins driven by a $34 million increase in the commercial and industrial customer classes partially offset by a $27 million decrease in the residential customer class.
A $5 million increase at KPCo due to base rate case revenues implemented in January 2021.
These increases were partially offset by:
A $7 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.
Margins from Off-system Salesincreased $6 million primarily due to favorable market prices in both PJM and SPP.
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Transmission Revenuesincreased $1 million due to a $10 million increase in transmission investment primarily at APCo offset by a $9 million decrease as a result of the annual formula rate true-up. This increase is partially offset in Depreciation and Amortization expenses below.

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

Other Operation and Maintenance expenses increased $79 million primarily due to the following:
A $47 million increase in PJM transmission services including the annual formula rate true-up.
A $25 million increase in SPP transmission services including the annual formula rate true-up.
A $23 million increase in employee-related expenses.
These increases were partially offset by:
A $20 million decrease in storms primarily at KPCo, APCo and PSO.
Depreciation and Amortizationexpenses increased $41 million primarily due to a higher depreciable base and an increase in depreciation rates at APCo. This increase was partially offset in Gross Margin above.
Taxes Other Than Income Taxesincreased $11 million primarily due to the following:
A $5 million increase in property taxes at SWEPCo resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.
A $4 million increase at I&M primarily due to property taxes driven by an increase in utility plant.
Other Incomeincreased $4 million primarily due to increased interest income related the February 2021 severe winter weather event at SWEPCo.
Income Tax Expenseincreased $4 million primarily due to a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT is partially offset above in Retail Margins.

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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Six Months Ended June 30, 2020 $ 501.2
Changes in Gross Margin:
Retail Margins 194.5
Margins from Off-system Sales 23.8
Transmission Revenues 11.2
Other Revenues (6.4)
Total Change in Gross Margin 223.1
Changes in Expenses and Other:
Other Operation and Maintenance (127.8)
Depreciation and Amortization (90.9)
Taxes Other Than Income Taxes (16.9)
Other Income 2.8
Allowance for Equity Funds Used During Construction 3.5
Interest Expense 5.1
Total Change in Expenses and Other (224.2)
Income Tax Expense (1.3)
Net Income Attributable to Noncontrolling Interests (0.2)
Six Months Ended June 30, 2021 $ 498.6

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, and purchased electricity were as follows:

Retail Marginsincreased $195 million primarily due to the following:
A $59 million increase in weather-related usage primarily in the residential class.
A $48 million increase at I&M due to wholesale true-up, Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
A $27 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
A $22 million increase at APCo and WPCo due to rider revenue primarily in West Virginia. This increase was partially offset in other expense items below.
A $19 million increase in revenue from rate riders at PSO. This increase was partially offset in other expense items below.
An $11 million increase at KPCo due to base rate case revenues implemented in January 2021.
A $10 million increase in weather-normalized wholesale margins at SWEPCo.
An $8 million increase in recoverable fuel costs at SWEPCo primarily due to timing of recovery.
A $5 million increase in municipal and cooperative revenues at SWEPCo primarily due to the annual generation formula rate true-up.
These increases were partially offset by:
A $23 million decrease in weather-normalized margins for wholesale contracts, including the loss of a significant wholesale contract at I&M.
A $17 million decrease in weather-normalized retail margins driven by a $10 million decrease in the residential class and a $7 million decrease in the industrial customer class.
Margins from Off-system Salesincreased $24 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
24




Transmission Revenuesincreased $11 million due to an increase in transmission investment primarily at APCo, partially offset by a $9 million decrease as a result of the transmission formula rate true-up. This increase is partially offset in Depreciation and Amortization expenses below.
Other Revenues decreased $6 million primarily due to business development revenue at PSO. This decrease was partially offset in Other Operation and Maintenance expenses below.

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

Other Operation and Maintenance expenses increased $128 million primarily due to the following:
A $78 million increase in PJM transmission services including the annual formula rate true-up.
A $31 million increase in SPP transmission services including the annual formula rate true-up.
A $29 million increase in employee-related expenses.
A $9 million increase primarily due to an increase in vegetation management expenses.
These increases were partially offset by:
A $15 million decrease due to storms primarily at KPCo, APCo and PSO.
A $9 million decrease in factoring expenses.
Depreciation and Amortizationexpenses increased $91 million primarily due to a higher depreciable base and increased depreciation rates at APCo and I&M. This increase was partially offset in Gross Margin above.
Taxes Other Than Income Taxesincreased $17 million primarily due to the following:
A $10 million increase at SWEPCo primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
A $4 million increase at I&M primarily due to property taxes driven by an increase in utility plant.
Interest Expensedecreased $5 million primarily due to the following:
A $3 million decrease at PSO primarily due to lower borrowing costs in 2021.
A $2 million decrease at I&M primarily due to a decrease in carrying charges and a decreased interest rate on variable rate notes.

25




TRANSMISSION AND DISTRIBUTION UTILITIES
Three Months Ended Six Months Ended
June 30, June 30,
Transmission and Distribution Utilities 2021 2020 2021 2020
(in millions)
Revenues $ 1,103.4 $ 1,034.5 $ 2,191.5 $ 2,141.4
Purchased Electricity 168.0 147.5 373.5 338.9
Gross Margin 935.4 887.0 1,818.0 1,802.5
Other Operation and Maintenance 360.8 351.9 726.0 719.1
Depreciation and Amortization 178.5 207.0 351.2 421.5
Taxes Other Than Income Taxes 158.4 141.8 316.0 288.0
Operating Income 237.7 186.3 424.8 373.9
Interest and Investment Income 0.3 0.4 0.7 1.1
Carrying Costs Income 0.5 0.6 1.0 1.0
Allowance for Equity Funds Used During Construction
6.2 7.7 13.0 14.7
Non-Service Cost Components of Net Periodic Benefit Cost 7.2 7.4 14.5 14.7
Interest Expense (77.0) (72.2) (151.5) (143.6)
Income Before Income Tax Expense (Benefit) 174.9 130.2 302.5 261.8
Income Tax Expense (Benefit) 21.2 (9.3) 34.4 6.1
Net Income 153.7 139.5 268.1 255.7
Net Income Attributable to Noncontrolling Interests - - - -
Earnings Attributable to AEP Common Shareholders
$ 153.7 $ 139.5 $ 268.1 $ 255.7

Summary of KWh Energy Sales for Transmission and Distribution Utilities
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 6,065 6,299 12,989 12,599
Commercial 6,488 5,559 12,064 11,432
Industrial 6,338 5,148 11,619 11,056
Miscellaneous 185 180 351 362
Total Retail (a) 19,076 17,186 37,023 35,449
Wholesale (b) 445 455 1,048 845
Total KWhs 19,521 17,641 38,071 36,294

(a)Represents energy delivered to distribution customers.
(b)Primarily Ohio's contractually obligated purchases of OVEC power sold to PJM.
26




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
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Eastern Region
Actual -Heating (a)
215 292 1,992 1,765
Normal -Heating (b)
183 182 2,066 2,080
Actual -Cooling (c)
361 314 361 317
Normal -Cooling (b)
304 301 307 304
Western Region
Actual -Heating (a)
4 6 319 97
Normal -Heating (b)
3 3 188 188
Actual -Cooling (d)
833 936 970 1,167
Normal -Cooling (b)
931 933 1,057 1,058

(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.

27




Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Second Quarter of 2020 $ 139.5
Changes in Gross Margin:
Retail Margins 76.5
Margins from Off-system Sales (18.7)
Transmission Revenues 30.0
Other Revenues (39.4)
Total Change in Gross Margin 48.4
Changes in Expenses and Other:
Other Operation and Maintenance (8.9)
Depreciation and Amortization 28.5
Taxes Other Than Income Taxes (16.6)
Interest and Investment Income (0.1)
Carrying Costs Income (0.1)
Allowance for Equity Funds Used During Construction (1.5)
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense (4.8)
Total Change in Expenses and Other (3.7)
Income Tax Expense (30.5)
Second Quarter of 2021 $ 153.7

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

Retail Marginsincreased $77 million primarily due to the following:
A $30 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $19 million increase in usage in Ohio primarily from the commercial and residential classes of $11 million and $6 million, respectively.
A $19 million increase in weather-normalized margins in Texas primarily in the residential and commercial classes.
A $16 million increase from interim rate increases driven by increased transmission investment in Texas.
A $12 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
An $11 million increase from interim rate increases driven by increased distribution investment in Texas.
An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This decrease was offset in Other Operation and Maintenance expenses below.
A $7 million increase in the Legacy Generation Resource Rider (LGRR) in Ohio. This increase was offset in Margins from Off-system Sales and Other Revenues below.
A $5 million increase in revenues associated with a vegetation management rider in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $19 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
28




An $11 million decrease in revenues in Ohio associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
A $6 million decrease in weather-related usage in Texas primarily due to an 11% decrease in cooling degree days.
A $4 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform.
Margins from Off-system Salesdecreased $19 million primarily due to the following:
A $13 million decrease in Ohio primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
A $5 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
Transmission Revenuesincreased $30 million primarily due to the following:
A $20 million increase from interim rate increases driven by increased transmission investment in Texas.
A $14 million increase due to a prior year one-time credit to transmission customers in Texas as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
These increases were partially offset by:
A $4 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
Other Revenuesdecreased $39 million primarily due to the following:
A $47 million decrease primarily due to securitization revenues due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and Interest Expense.
This decrease was partially offset by:
An $8 million increase primarily due to third-party LGRR revenue related to the recovery of OVEC costs in Ohio. This increase was offset in Retail Margins and Margins from Off-system Sales above.

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

Other Operation and Maintenanceexpenses increased $9 million primarily due to the following:
A $26 million increase in recoverable PJM expense in Ohio. This increase was partially offset in Retail Margins above.
A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
A $9 million increase in PJM expenses in Ohio primarily related to the annual formula rate true-up.
An $8 million increase in distribution maintenance expenses in Ohio related to the annual major storm reserve true-up. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $19 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
An $11 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
A $9 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
A $7 million decrease in factored customer accounts receivable expenses in Ohio primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
Depreciation and Amortizationexpenses decreased $29 million primarily due to the following:
A $49 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020.This decrease was offset in Other Revenues above.
These decreases were partially offset by:
A $9 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
29




A $6 million increase in recoverable DIR depreciable expense in Ohio. This increase was partially offset in Retail Margins above.
A $5 million increase in amortization primarily related to capitalized software in Ohio.
Taxes Other Than Income Taxesincreased $17 million primarily due to increased property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expenseincreased $5 million primarily due to higher long-term debt balances.
Income Tax Expenseincreased $31 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin.

30




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Six Months Ended June 30, 2020 $ 255.7
Changes in Gross Margin:
Retail Margins 101.2
Margins from Off-system Sales (56.1)
Transmission Revenues 42.5
Other Revenues (72.1)
Total Change in Gross Margin 15.5
Changes in Expenses and Other:
Other Operation and Maintenance (6.9)
Depreciation and Amortization 70.3
Taxes Other Than Income Taxes (28.0)
Interest and Investment Income (0.4)
Allowance for Equity Funds Used During Construction (1.7)
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense (7.9)
Total Change in Expenses and Other 25.2
Income Tax Expense (28.3)
Six Months Ended June 30, 2021 $ 268.1

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

Retail Marginsincreased $101 million primarily due to the following:
An $88 million net increase in Ohio Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $21 million increase from interim rate increases driven by increased transmission investment in Texas.
A $21 million increase from interim rate increases driven by increased distribution investment in Texas.
A $19 million increase in usage in Ohio from the commercial and residential classes of $11 million and $8 million, respectively.
A $17 million increase in rider revenues in Ohio associated with the DIR. This increase was partially offset in other expense items below.
A $15 million increase in the LGRR in Ohio. This increase was offset in Margins from Off-system Sales and Other Revenues below.
A $13 million increase in weather-related usage in Texas primarily due to a 229% increase in heating degree days, partially offset by a 17% decrease in cooling degree days.
A $10 million increase in revenues associated with a vegetation management rider in Ohio. This increase was partially offset in Other Operation and Maintenance expenses below.
An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This increase was offset in Other Operation and Maintenance expenses below.


31




These increases were partially offset by:
A $46 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in Ohio in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $27 million decrease in revenues in Ohio associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
A $19 million decrease due to refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
A $6 million decrease in weather-normalized margins in Texas primarily in the industrial and residential classes, partially offset by an increase in the commercial class.
Margins from Off-system Salesdecreased $56 million primarily due to the following:
A $29 million decrease in Texas primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
A $27 million decrease in Ohio primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
Transmission Revenuesincreased $43 million primarily due to the following:
A $39 million increase from interim rate increases driven by increased transmission investment in Texas.
A $14 million increase due to a prior year one-time credit to transmission customers in Texas as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
These increases were partially offset by:
A $9 million decrease due to refunds to customers associated with the most recent base rate case in Texas. This decrease was offset in Other Revenues below.
Other Revenuesdecreased $72 million primarily due to the following:
A $98 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
This decrease was partially offset by:
A $13 million increase in Ohio primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
A $10 million increase due to refunds in Texas to customers associated with the most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.

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

Other Operation and Maintenanceexpenses increased $7 million primarily due to the following:
A $78 million increase in recoverable PJM expenses in Ohio. This increase was partially offset in Retail Margins above.
A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
A $10 million increase in recoverable distribution expenses related to vegetation management in Ohio. This increase was offset in Retail Margins above.
A $9 million increase in PJM expenses in Ohio primarily related to the annual formula rate true-up.
An $8 million increase in distribution maintenance expenses in Ohio related to the annual major storm reserve true-up. This increase was offset in Retail Margins above.
These increases were partially offset by:
A $39 million decrease in Texas due to the Oklaunion Power Station retirement in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
A $30 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
A $27 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
A $14 million decrease in factored customer accounts receivable expenses in Ohio primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
32




A $6 million decrease primarily related to distribution related expenses in Texas.
Depreciation and Amortizationexpenses decreased $70 million primarily due to the following:
A $93 million decrease in securitization amortizations in Texas primarily related to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020.This decrease was offset in Other Revenues above.
These decreases were partially offset by:
A $13 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $6 million increase in recoverable DIR depreciable expense in Ohio. This increase was partially offset in Retail Margins above.
A $6 million increase in amortization primarily related to capitalized software in Ohio.
Taxes Other Than Income Taxesincreased $28 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expense increased $8 million primarily due to higher long-term debt balances.
Income Tax Expense increased $28 million primarily due to a decrease in amortization of Excess ADIT and an increase in pretax book income. The decrease in amortization of Excess ADIT is partially offset above in Gross Margin.
33




AEP TRANSMISSION HOLDCO
Three Months Ended Six Months Ended
June 30, June 30,
AEP Transmission Holdco 2021 2020 2021 2020
(in millions)
Transmission Revenues $ 378.2 $ 249.7 $ 755.2 $ 559.9
Other Operation and Maintenance 29.4 25.9 56.6 55.8
Depreciation and Amortization 74.7 61.1 147.4 119.2
Taxes Other Than Income Taxes 61.5 51.8 120.7 103.7
Operating Income 212.6 110.9 430.5 281.2
Interest and Investment Income
0.2 1.5 0.4 2.4
Allowance for Equity Funds Used During Construction
16.5 18.4 33.2 34.6
Non-Service Cost Components of Net Periodic Benefit Cost 0.6 0.5 1.1 1.0
Interest Expense (35.5) (34.2) (70.8) (65.0)
Income Before Income Tax Expense and Equity Earnings 194.4 97.1 394.4 254.2
Income Tax Expense 43.4 24.7 89.2 63.1
Equity Earnings of Unconsolidated Subsidiary 18.6 19.8 37.6 42.7
Net Income 169.6 92.2 342.8 233.8
Net Income Attributable to Noncontrolling Interests 0.9 0.7 2.1 1.7
Earnings Attributable to AEP Common Shareholders $ 168.7 $ 91.5 $ 340.7 $ 232.1

Summary of Investment in Transmission Assets for AEP Transmission Holdco
June 30,
2021 2020
(in millions)
Plant in Service $ 11,065.2 $ 9,333.7
Construction Work in Progress 1,486.3 1,660.5
Accumulated Depreciation and Amortization 703.1 508.2
Total Transmission Property, Net $ 11,848.4 $ 10,486.0
34




Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Second Quarter of 2020 $ 91.5
Changes in Transmission Revenues:
Transmission Revenues 128.5
Total Change in Transmission Revenues 128.5
Changes in Expenses and Other:
Other Operation and Maintenance (3.5)
Depreciation and Amortization (13.6)
Taxes Other Than Income Taxes (9.7)
Interest Income (1.3)
Allowance for Equity Funds Used During Construction (1.9)
Non-Service Cost Components of Net Periodic Pension Cost 0.1
Interest Expense (1.3)
Total Change in Expenses and Other (31.2)
Income Tax Expense (18.7)
Equity Earnings of Unconsolidated Subsidiary (1.2)
Net Income Attributable to Noncontrolling Interests (0.2)
Second Quarter of 2021 $ 168.7

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

Transmission Revenuesincreased $129 million primarily due to the following:
A $68 million increase due to continued investment in transmission assets.
A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $16 million increase as a result of the non-affiliated annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenanceexpenses increased $4 million primarily due to vegetation management expenses.
Depreciation and Amortizationexpenses increased $14 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxesincreased $10 million primarily due to higher property taxes as a result of increased transmission investment.
Income Tax Expense increased $19 million primarily due to an increase in pretax book income.
35




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
Six Months Ended June 30, 2020 $ 232.1
Changes in Transmission Revenues:
Transmission Revenues 195.3
Total Change in Transmission Revenues 195.3
Changes in Expenses and Other:
Other Operation and Maintenance (0.8)
Depreciation and Amortization (28.2)
Taxes Other Than Income Taxes (17.0)
Interest Income (2.0)
Allowance for Equity Funds Used During Construction (1.4)
Non-Service Cost Components of Net Periodic Pension Cost 0.1
Interest Expense (5.8)
Total Change in Expenses and Other (55.1)
Income Tax Expense (26.1)
Equity Earnings of Unconsolidated Subsidiary (5.1)
Net Income Attributable to Noncontrolling Interests (0.4)
Six Months Ended June 30, 2021 $ 340.7

The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
Transmission Revenues increased $195 million primarily due to the following:
A $134 million increase due to continued investment in transmission assets.
A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $16 million increase as a result of the non-affiliated annual transmission formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:
Depreciation and Amortizationexpenses increased $28 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxesincreased $17 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expenseincreased $6 million primarily due to higher long-term debt balances.
Income Tax Expenseincreased $26 million primarily due to an increase in pretax book income.
Equity Earnings of Unconsolidated Subsidiarydecreased $5 million primarily due to lower pretax equity earnings at PATH-WV and ETT.
36




GENERATION & MARKETING
Three Months Ended Six Months Ended
June 30, June 30,
Generation & Marketing 2021 2020 2021 2020
(in millions)
Revenues $ 436.6 $ 376.9 $ 1,070.8 $ 815.5
Fuel, Purchased Electricity and Other 358.1 298.5 924.0 658.8
Gross Margin 78.5 78.4 146.8 156.7
Other Operation and Maintenance 32.4 16.5 60.6 57.9
Depreciation and Amortization 20.0 17.9 38.6 35.6
Taxes Other Than Income Taxes 2.9 3.7 5.5 7.1
Operating Income 23.2 40.3 42.1 56.1
Interest and Investment Income 0.6 1.2 1.1 2.2
Non-Service Cost Components of Net Periodic Benefit Cost 3.9 3.8 7.7 7.7
Interest Expense (3.8) (8.2) (7.1) (16.7)
Income Before Income Tax Benefit and Equity Earnings (Loss) 23.9 37.1 43.8 49.3
Income Tax Benefit (24.2) (21.0) (39.3) (33.4)
Equity Earnings (Loss) of Unconsolidated Subsidiaries (1.6) 0.4 1.6 6.3
Net Income 46.5 58.5 84.7 89.0
Net Loss Attributable to Noncontrolling Interests (5.9) (7.4) (4.3) (5.3)
Earnings Attributable to AEP Common Shareholders
$ 52.4 $ 65.9 $ 89.0 $ 94.3

Summary of MWhs Generated for Generation & Marketing
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of MWhs)
Fuel Type:
Coal 1 1 2 2
Renewables 1 1 2 2
Total MWhs 2 2 4 4
37




Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Second Quarter of 2020 $ 65.9
Changes in Gross Margin:
Merchant Generation 5.1
Renewable Generation 3.1
Retail, Trading and Marketing (8.1)
Total Change in Gross Margin 0.1
Changes in Expenses and Other:
Other Operation and Maintenance (15.9)
Depreciation and Amortization (2.1)
Taxes Other Than Income Taxes 0.8
Interest and Investment Income (0.6)
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense 4.4
Total Change in Expenses and Other (13.3)
Income Tax Benefit 3.2
Equity Earnings of Unconsolidated Subsidiaries (2.0)
Net Loss Attributable to Noncontrolling Interests (1.5)
Second Quarter of 2021 $ 52.4

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 $5 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
Renewable Generation increased $3 million primarily due to higher solar and wind production.
Retail, Trading and Marketing decreased $8 million due to lower wholesale marketing activity.

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

Other Operation and Maintenanceexpenses increased $16 million primarily due to the following:
A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
An $8 million increase due to gains recorded in 2020 on the sale of land.
These increases were partially offset by:
A $9 million decrease in expenses related to the retirements of Conesville Plant Unit 4 and Oklaunion Plant in 2020.
Interest Expensedecreased $4 million due to lower borrowing costs in 2021.
Income Tax Benefitincreased $3 million due to an increase in PTCs.

38




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to AEP Common Shareholders from Generation & Marketing
(in millions)
Six Months Ended June 30, 2020 $ 94.3
Changes in Gross Margin:
Merchant Generation 9.1
Renewable Generation 8.4
Retail, Trading and Marketing (27.4)
Total Change in Gross Margin (9.9)
Changes in Expenses and Other:
Other Operation and Maintenance (2.7)
Depreciation and Amortization (3.0)
Taxes Other Than Income Taxes 1.6
Interest and Investment Income (1.1)
Interest Expense 9.6
Total Change in Expenses and Other 4.4
Income Tax Benefit 5.9
Equity Earnings of Unconsolidated Subsidiaries (4.7)
Net Loss Attributable to Noncontrolling Interests (1.0)
Six Months Ended June 30, 2021 $ 89.0

The major components of the decrease 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 $9 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
Renewable Generationincreased $8 million primarily due to increased solar and wind production in the ERCOT region and higher market revenues from wind assets in the ERCOT region.
Retail, Trading and Marketing decreased $27 million due to lower trading and retail margins due to unprecedented cold temperatures and record ERCOT market prices in February 2021.

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

Other Operation and Maintenanceexpenses increased $3 million primarily due to the following:
A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
This increase was partially offset by:
A $9 million decrease due to the retirement of Conesville Plant Unit 4 in 2020.
A $4 million decrease due to a planned outage at Cardinal Plant in 2020.
Depreciation and Amortization expenses increased $3 million due to a higher depreciable base from increased investments in renewable energy sources.
Interest Expense decreased $10 million due to lower borrowing costs in 2021.
Income Tax Benefitincreased $6 million primarily due to an increase in PTCs.
Equity Earnings of Unconsolidated Subsidiaries decreased $5 million primarily due to lower revenues due to lower wind production from jointly owned assets.
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CORPORATE AND OTHER

Second Quarter of 2021 Compared to Second Quarter of 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $32 million in 2020 to a loss of $25 million in 2021 primarily due to:

A $21 million gain from an investment in ChargePoint, of which $16 million is unrealized.
A $14 million increase in equity earnings.
A $4 million decrease in interest expense.

These items were partially offset by:

A $19 million increase in general corporate expenses.
A $14 million decrease in interest income due to a lower return on investments held by EIS and lower interest income from affiliates.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Earnings Attributable to AEP Common Shareholders from Corporate and Other increased from a loss of $67 million in 2020 to a loss of $43 million in 2021 primarily due to:

A $38 million gain from an investment in ChargePoint, of which $33 million is unrealized.
A $20 million increase in equity earnings.
A $16 million decrease in interest expense.

These items were partially offset by:

A $28 million increase in general corporate expenses.
A $15 million decrease in interest income primarily due to lower interest income from affiliates.
A $7 million increase in Income Tax Expense due to the recognition of a $19 million remeasurement of state deferred taxes as a result of newly enacted West Virginia state legislation in 2021 partially offset by a decrease in consolidating tax adjustments.

AEP SYSTEM INCOME TAXES

Second Quarter of 2021 Compared to Second Quarter of 2020

Income Tax Expense increased $49 million primarily due to a decrease in amortization of Excess ADIT, an increase in pretax book income and the remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Income Tax Expense increased $57 million primarily due to an increase in pretax book income, a decrease in amortization of Excess ADIT and the remeasurement of state deferred taxes as a result of newly enacted West Virginia and Oklahoma state legislation in 2021, partially offset by an increase in PTCs.


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FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization
June 30, 2021 December 31, 2020
(dollars in millions)
Long-term Debt, including amounts due within one year $ 33,117.8 57.2 % $ 31,072.5 57.2 %
Short-term Debt 3,128.0 5.4 2,479.3 4.6
Total Debt 36,245.8 62.6 33,551.8 61.8
AEP Common Equity 21,378.7 37.0 20,550.9 37.8
Noncontrolling Interests 251.2 0.4 223.6 0.4
Total Debt and Equity Capitalization $ 57,875.7 100.0 % $ 54,326.3 100.0 %

AEP's ratio of debt-to-total capital increased from 61.8% as of December 31, 2020 to 62.6% as of June 30, 2021 primarily due to an increase in debt to help address the cash flow implications resulting from the February 2021 severe winter weather event in addition to supporting distribution, transmission and renewable investment growth.

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 June 30, 2021, AEP had $5 billion of 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. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. 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. See Note 4 - Rate Matters for additional information.

Net Available Liquidity

AEP manages liquidity by maintaining adequate external financing commitments. As of June 30, 2021, available liquidity was approximately $3.3 billion as illustrated in the table below:
Amount Maturity
Commercial Paper Backup: (in millions)
Revolving Credit Facility $ 4,000.0 March 2026
Revolving Credit Facility 1,000.0 March 2023
364-Day Term Loan 500.0 March 2022
Cash and Cash Equivalents 312.7
Total Liquidity Sources 5,812.7
Less: AEP Commercial Paper Outstanding 2,049.8
364-Day Term Loan 500.0
Net Available Liquidity $ 3,262.9

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 the first six months of 2021 was $2.5 billion. The weighted-average interest rate for AEP's commercial paper during 2021 was 0.25%.
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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 six uncommitted facilities totaling $425 million. The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2021 was $187 million with maturities ranging from July 2021 to July 2022.

Securitized Accounts Receivables

AEP's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022.

In March 2021, AEP Credit amended its receivables securitization agreement to extend trigger levels established in October 2020 and to also provide a step down approach to these levels as management continues to monitor the accounts receivable balances across the affiliated utility subsidiaries in response to the COVID-19 pandemic. In June 2021, AEP Credit entered into a waiver for both APCo and SWEPCo to waive certain triggers through August 2021 due to the continuing impact of the COVID-19 pandemic. As of June 30, 2021, the affiliated utility subsidiaries are in compliance with all requirements under the agreement. To the extent that an affiliated utility subsidiary is deemed ineligible under the agreement, the affiliated utility subsidiary would no longer participate in the receivables securitization agreement and the Registrants would need to rely on additional sources of funding for operation and working capital, which may adversely impact liquidity. The receivables that are ineligible under the receivables securitization agreement are financed with short-term debt at AEP Credit.

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 June 30, 2021, this contractually-defined percentage was 59.7%. 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 facilities do 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.

At-the-Market (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. As of June 30, 2021, approximately $803 million of equity is available for issuance under the ATM offering program. See Note 12 - 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 2023. The proceeds were used to support AEP's overall capital expenditure plans.
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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 settles 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.

See Note 12 - Financing Activities for additional information.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.74 per share in July 2021. 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 12 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.


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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.
Six Months Ended
June 30,
2021 2020
(in millions)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period $ 438.3 $ 432.6
Net Cash Flows from Operating Activities 1,043.9 1,746.2
Net Cash Flows Used for Investing Activities (3,229.8) (3,247.6)
Net Cash Flows from Financing Activities 2,107.3 1,573.5
Net Increase (Decrease) in Cash and Cash Equivalents (78.6) 72.1
Cash, Cash Equivalents and Restricted Cash at End of Period $ 359.7 $ 504.7

Operating Activities
Six Months Ended
June 30,
2021 2020
(in millions)
Net Income $ 1,152.6 $ 1,013.8
Non-Cash Adjustments to Net Income (a) 1,530.6 1,459.1
Mark-to-Market of Risk Management Contracts 26.1 13.7
Property Taxes 167.3 173.6
Deferred Fuel Over/Under-Recovery, Net (1,218.2) 76.0
Change in Other Noncurrent Assets (291.9) (143.9)
Change in Other Noncurrent Liabilities 163.5 (50.0)
Change in Certain Components of Working Capital (486.1) (796.1)
Net Cash Flows from Operating Activities $ 1,043.9 $ 1,746.2

(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Operating Lease Amortization, Deferred Income Taxes, AFUDC and Amortization of Nuclear Fuel.

Net Cash Flows from Operating Activitiesdecreased by $702 million primarily due to the following:
A $1.3 billion decrease in cash primarily due to fuel and purchased power expenses incurred as a result of the February 2021 severe winter weather event in SPP impacting PSO and SWEPCo. Approximately $1.1 billion of these expenses are attributable to retail customers and are recorded as deferred fuel regulatory assets. PSO and SWEPCo are working with their respective regulatory commissions to determine the recovery period from customers as well as the appropriate carrying charge on the regulatory assets. See Note 4 - Rate Matters for additional information.
A $138 million decrease in cash due to incremental other operation and maintenance storm restoration expenses incurred by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. These incremental expenses have been deferred as regulatory assets. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCO and SWEPCo are expected to seek recovery in separate filings. See Note 4 - Rate Matters for additional information.
These decreases in cash were partially offset by:
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A $310 million increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to timing of accounts receivables and payables and a decrease in fuel, material and supplies balances primarily driven by changes in power prices.
A $214 million increase in cash from Change in Other Noncurrent Liabilities. The increase is primarily due to changes in regulatory liabilities driven by timing differences between collections from and refunds to customers under rate rider mechanisms.
A $210 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.


Investing Activities
Six Months Ended
June 30,
2021 2020
(in millions)
Construction Expenditures $ (2,784.8) $ (3,244.9)
Acquisitions of Nuclear Fuel (63.0) (37.7)
Acquisition of the North Central Wind Energy Facilities (270.0) -
Acquisition of the Dry Lake Solar Project (114.3) -
Other 2.3 35.0
Net Cash Flows Used for Investing Activities $ (3,229.8) $ (3,247.6)

Net Cash Flows Used for Investing Activitiesdecreased by $18 million primarily due to the following:
A $460 million decrease in construction expenditures, primarily due to decreases in Transmission and Distribution Utilities of $194 million, Vertically Integrated Utilities of $173 million and AEP Transmission Holdco of $90 million.
This decrease in the use of cash was partially offset by:
A $384 million increase due to the acquisition of the North Central Wind Energy Facilities and the Dry Lake Solar Project. See Note 6 - Acquisitions and Dispositions for additional information.

Financing Activities
Six Months Ended
June 30,
2021 2020
(in millions)
Issuance of Common Stock $ 256.9 $ 111.0
Issuance/Retirement of Debt, Net 2,705.7 2,236.4
Dividends Paid on Common Stock (746.5) (704.6)
Other (108.8) (69.3)
Net Cash Flows from Financing Activities $ 2,107.3 $ 1,573.5

Net Cash Flows from Financing Activitiesincreased by $534 million primarily due to the following:
A $624 million increase in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
A $410 million increase in short-term debt primarily due to increased draws on commercial paper. See Note 12 - Financing Activities for additional information.
A $146 million increase in issuances of common stock primarily due to AEP's participation in an At-the-Market offering program. See Note 12 - Financing Activities for additional information.
These increases in cash were partially offset by:
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A $565 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.

See 'Long-term Debt Subsequent Events' section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after June 30, 2021 through July 22, 2021, the date that the second quarter 10-Q was issued.

BUDGETED CAPITAL EXPENDITURES

Management forecasts approximately $7.5 billion of capital expenditures in 2021. For the four year period, 2022 through 2025, management forecasts capital expenditures of $29.8 billion. The expenditures are generally for transmission, generation, distribution, regulated and contracted 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, weather, legal reviews and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations 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. For complete information of forecasted capital expenditures, see the 'Budgeted Capital Expenditures' section of 'Management's Discussion and Analysis of Financial Condition and Results of Operations' in the 2020 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2020 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the 'Cash Flow' section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the 'Critical Accounting Policies and Estimates' section of 'Management's Discussion and Analysis of Financial Condition and Results of Operations' in the 2020 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, derivative instruments, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting standards.

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.

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.


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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 Commercial Operations Risk Committee (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 Operating Officer, Executive Vice President of Generation, 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, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply's President and Vice President. 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.

The effects of COVID-19 continue to be monitored, and while markets have shown improvement, credit risks remain as counterparties encounter business and supply chain disruptions.

Due to multiple defaults of market participants, ERCOT has a large outstanding unpaid balance associated with the February storm. Socialized losses are allocated to load serving entities through their qualified scheduling entities and in that 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, 2020:
MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2021
Vertically
Integrated
Utilities
Transmission
and
Distribution
Utilities
Generation
&
Marketing
Total
(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2020 $ 41.2 $ (109.5) $ 168.1 $ 99.8
Gain from Contracts Realized/Settled During the Period and Entered in a Prior Period
(20.7) (4.6) (6.8) (32.1)
Fair Value of New Contracts at Inception When Entered During the Period (a)
- - 0.4 0.4
Changes in Fair Value Due to Market Fluctuations During the Period (b) - - 30.0 30.0
Changes in Fair Value Allocated to Regulated Jurisdictions (c) 61.7 10.6 - 72.3
Total MTM Risk Management Contract Net Assets (Liabilities) as of June 30, 2021 $ 82.2 $ (103.5) $ 191.7 170.4
Commodity Cash Flow Hedge Contracts
139.7
Fair Value Hedge Contracts
(25.2)
Collateral Deposits
(93.0)
Total MTM Derivative Contract Net Assets as of June 30, 2021
$ 191.9

(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.

See Note 9 - Derivatives and Hedging and Note 10 - 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 June 30, 2021, credit exposure net of collateral to sub investment grade counterparties was approximately 3.1%, 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 June 30, 2021, 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 $ 397.5 $ 0.1 $ 397.4 2 $ 156.5
Split Rating 0.2 - 0.2 1 0.2
No External Ratings:
Internal Investment Grade 98.4 - 98.4 3 72.9
Internal Noninvestment Grade 17.0 1.4 15.6 2 9.4
Total as of June 30, 2021 $ 513.1 $ 1.5 $ 511.6

All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of 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 June 30, 2021, 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.

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

VaR Model
Trading Portfolio
Six Months Ended Twelve Months Ended
June 30, 2021 December 31, 2020
End High Average Low End High Average Low
(in millions) (in millions)
$ 0.2 $ 3.6 $ 0.2 $ 0.1 $ 0.1 $ 0.3 $ 0.1 $ -
VaR Model
Non-Trading Portfolio
Six Months Ended Twelve Months Ended
June 30, 2021 December 31, 2020
End High Average Low End High Average Low
(in millions) (in millions)
$ 1.8 $ 3.7 $ 1.7 $ 0.7 $ 2.2 $ 2.9 $ 1.0 $ 0.1

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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. AEP has outstanding short and long-term debt which is subject to a variable rate. 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 six months ended June 30, 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 $38 million and $17 million, respectively.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions, except per-share and share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Vertically Integrated Utilities $ 2,224.6 $ 2,062.3 $ 4,729.1 $ 4,255.3
Transmission and Distribution Utilities 1,089.6 1,009.4 2,171.9 2,084.6
Generation & Marketing 422.5 350.2 1,024.2 758.6
Other Revenues 89.8 72.1 182.4 143.0
TOTAL REVENUES 3,826.5 3,494.0 8,107.6 7,241.5
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 1,124.0 964.9 2,684.7 2,115.9
Other Operation 566.9 566.0 1,159.3 1,168.1
Maintenance 264.3 243.4 539.2 492.9
Depreciation and Amortization 707.3 679.5 1,403.6 1,351.7
Taxes Other Than Income Taxes 354.1 317.5 700.6 638.6
TOTAL EXPENSES 3,016.6 2,771.3 6,487.4 5,767.2
OPERATING INCOME 809.9 722.7 1,620.2 1,474.3
Other Income (Expense):
Other Income 33.1 14.3 54.8 9.9
Allowance for Equity Funds Used During Construction 33.5 35.1 66.9 66.5
Non-Service Cost Components of Net Periodic Benefit Cost 29.7 29.8 59.3 59.5
Interest Expense (301.6) (294.0) (591.8) (586.1)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 604.6 507.9 1,209.4 1,024.1
Income Tax Expense 61.2 12.6 115.7 59.1
Equity Earnings of Unconsolidated Subsidiaries 30.4 19.2 58.9 48.8
NET INCOME 573.8 514.5 1,152.6 1,013.8
Net Loss Attributable to Noncontrolling Interests (4.4) (6.3) (0.6) (2.2)
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 578.2 $ 520.8 $ 1,153.2 $ 1,016.0
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
499,916,640 495,655,053 498,495,532 495,125,961
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$ 1.16 $ 1.05 $ 2.31 $ 2.05
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING 500,983,778 497,337,980 499,581,893 496,973,449
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$ 1.15 $ 1.05 $ 2.31 $ 2.04
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 573.8 $ 514.5 $ 1,152.6 $ 1,013.8
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $34.5 and $12.0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $49.5 and $(5.8) for the Six Months Ended June 30, 2021 and 2020, Respectively
129.9 45.3 186.2 (21.7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.6) and $(0.4) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(1.1) and $(0.9) for the Six Months Ended June 30, 2021 and 2020, Respectively
(2.1) (1.7) (4.1) (3.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) 127.8 43.6 182.1 (25.2)
TOTAL COMPREHENSIVE INCOME 701.6 558.1 1,334.7 988.6
Total Comprehensive Loss Attributable To Noncontrolling Interests (4.4) (6.3) (0.6) (2.2)
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS $ 706.0 $ 564.4 $ 1,335.3 $ 990.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
52




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
AEP Common Shareholders
Common Stock Accumulated
Other
Comprehensive
Income (Loss)
Shares Amount Paid-in
Capital
Retained
Earnings
Noncontrolling
Interests
Total
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 1.0 6.8 49.3 56.1
Common Stock Dividends (359.1) (a) (4.6) (363.7)
Other Changes in Equity (29.0) (1.2) (30.2)
ASU 2016-13 Adoption 1.8 1.8
Net Income 495.2 4.1 499.3
Other Comprehensive Loss (68.8) (68.8)
TOTAL EQUITY - MARCH 31, 2020 515.4 3,350.2 6,555.9 10,038.8 (216.5) 279.3 20,007.7
Issuance of Common Stock 0.8 5.2 49.7 54.9
Common Stock Dividends (337.7) (a) (3.2) (340.9)
Other Changes in Equity (2.6) 1.0 (1.6)
Net Income (Loss) 520.8 (6.3) 514.5
Other Comprehensive Income 43.6 43.6
TOTAL EQUITY - JUNE 30, 2020 516.2 $ 3,355.4 $ 6,603.0 $ 10,221.9 $ (172.9) $ 270.8 $ 20,278.2
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 2.7 17.1 167.5 184.6
Common Stock Dividends (369.5) (b) (2.5) (372.0)
Other Changes in Equity (21.9) (0.6) 3.4 (19.1)
Acquisition of Dry Lake Solar Project 18.9 18.9
Net Income 575.0 3.8 578.8
Other Comprehensive Income 54.3 54.3
TOTAL EQUITY - MARCH 31, 2021 519.5 3,376.4 6,734.5 10,892.7 (30.8) 247.2 21,220.0
Issuance of Common Stock 0.9 6.3 66.0 72.3
Common Stock Dividends (371.8) (b) (2.7) (374.5)
Other Changes in Equity (0.2) (0.4) 11.1 10.5
Net Income (Loss) 578.2 (4.4) 573.8
Other Comprehensive Income 127.8 127.8
TOTAL EQUITY - JUNE 30, 2021 520.4 $ 3,382.7 $ 6,800.3 $ 11,098.7 $ 97.0 $ 251.2 $ 21,629.9

(a) Cash dividends declared per AEP common share were $0.70.
(b) Cash dividends declared per AEP common share were $0.74.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
53




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 312.7 $ 392.7
Restricted Cash
(June 30, 2021 and December 31, 2020 Amounts Include $47 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding)
47.0 45.6
Other Temporary Investments
(June 30, 2021 and December 31, 2020 Amounts Include $204.9 and $194.6, Respectively, Related to EIS and Transource Energy)
221.7 200.8
Accounts Receivable:
Customers 794.8 613.6
Accrued Unbilled Revenues 259.6 248.7
Pledged Accounts Receivable - AEP Credit 1,003.1 1,018.4
Miscellaneous 66.6 33.1
Allowance for Uncollectible Accounts (50.3) (71.1)
Total Accounts Receivable 2,073.8 1,842.7
Fuel 512.2 629.4
Materials and Supplies 676.2 680.6
Risk Management Assets 214.7 94.7
Accrued Tax Benefits 189.8 185.3
Regulatory Asset for Under-Recovered Fuel Costs 180.3 90.7
Margin Deposits 43.5 62.0
Prepayments and Other Current Assets 133.9 127.0
TOTAL CURRENT ASSETS 4,605.8 4,351.5
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 23,687.3 23,133.9
Transmission 29,213.7 27,886.7
Distribution 24,704.6 23,972.1
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 5,571.4 5,294.6
Construction Work in Progress 3,879.3 4,025.7
Total Property, Plant and Equipment 87,056.3 84,313.0
Accumulated Depreciation and Amortization 21,391.8 20,411.4
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 65,664.5 63,901.6
OTHER NONCURRENT ASSETS
Regulatory Assets 5,048.2 3,527.0
Securitized Assets 608.0 657.0
Spent Nuclear Fuel and Decommissioning Trusts 3,612.4 3,306.7
Goodwill 52.5 52.5
Long-term Risk Management Assets 241.3 242.2
Operating Lease Assets 797.6 866.4
Deferred Charges and Other Noncurrent Assets 3,727.9 3,852.3
TOTAL OTHER NONCURRENT ASSETS 14,087.9 12,504.1
TOTAL ASSETS $ 84,358.2 $ 80,757.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
54




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2021 and December 31, 2020
(in millions, except per-share and share amounts)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT LIABILITIES
Accounts Payable $ 1,641.6 $ 1,709.7
Short-term Debt:
Securitized Debt for Receivables - AEP Credit 578.2 592.0
Other Short-term Debt 2,549.8 1,887.3
Total Short-term Debt 3,128.0 2,479.3
Long-term Debt Due Within One Year
(June 30, 2021 and December 31, 2020 Amounts Include $210.2 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
2,458.5 2,086.1
Risk Management Liabilities 47.8 78.8
Customer Deposits 350.1 335.6
Accrued Taxes 1,243.5 1,476.4
Accrued Interest 274.0 267.6
Obligations Under Operating Leases 242.7 241.3
Regulatory Liability for Over-Recovered Fuel Costs 32.7 52.6
Other Current Liabilities 1,009.7 1,199.3
TOTAL CURRENT LIABILITIES 10,428.6 9,926.7
NONCURRENT LIABILITIES
Long-term Debt
(June 30, 2021 and December 31, 2020 Amounts Include $922.5 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy)
30,659.3 28,986.4
Long-term Risk Management Liabilities 216.3 232.8
Deferred Income Taxes 8,382.1 8,240.9
Regulatory Liabilities and Deferred Investment Tax Credits 8,767.5 8,378.7
Asset Retirement Obligations 2,576.2 2,469.2
Employee Benefits and Pension Obligations 340.1 336.4
Obligations Under Operating Leases 568.4 638.4
Deferred Credits and Other Noncurrent Liabilities 724.9 728.0
TOTAL NONCURRENT LIABILITIES 52,234.8 50,010.8
TOTAL LIABILITIES 62,663.4 59,937.5
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEZZANINE EQUITY
Contingently Redeemable Performance Share Awards 64.9 45.2
TOTAL MEZZANINE EQUITY 64.9 45.2
EQUITY
Common Stock - Par Value - $6.50 Per Share:
2021 2020
Shares Authorized 600,000,000 600,000,000
Shares Issued 520,422,130 516,808,354
(20,204,160 Shares were Held in Treasury as of June 30, 2021 and December 31, 2020, Respectively)
3,382.7 3,359.3
Paid-in Capital 6,800.3 6,588.9
Retained Earnings 11,098.7 10,687.8
Accumulated Other Comprehensive Income (Loss) 97.0 (85.1)
TOTAL AEP COMMON SHAREHOLDERS' EQUITY 21,378.7 20,550.9
Noncontrolling Interests 251.2 223.6
TOTAL EQUITY 21,629.9 20,774.5
TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY $ 84,358.2 $ 80,757.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
55




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 1,152.6 $ 1,013.8
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 1,403.6 1,351.7
Rockport Plant, Unit 2 Operating Lease Amortization 66.8 68.3
Deferred Income Taxes 86.7 60.0
Allowance for Equity Funds Used During Construction (66.9) (66.5)
Mark-to-Market of Risk Management Contracts 26.1 13.7
Amortization of Nuclear Fuel 40.4 45.6
Property Taxes 167.3 173.6
Deferred Fuel Over/Under-Recovery, Net (1,218.2) 76.0
Change in Other Noncurrent Assets (291.9) (143.9)
Change in Other Noncurrent Liabilities 163.5 (50.0)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (215.5) (80.7)
Fuel, Materials and Supplies 132.3 (120.3)
Accounts Payable 97.5 (64.7)
Accrued Taxes, Net (237.4) (164.4)
Rockport Plant, Unit 2 Operating Lease Payments (73.9) (73.9)
Other Current Assets 10.4 18.8
Other Current Liabilities (199.5) (310.9)
Net Cash Flows from Operating Activities 1,043.9 1,746.2
INVESTING ACTIVITIES
Construction Expenditures (2,784.8) (3,244.9)
Purchases of Investment Securities (1,162.8) (988.4)
Sales of Investment Securities 1,131.8 971.3
Acquisitions of Nuclear Fuel (63.0) (37.7)
Acquisition of the Dry Lake Solar Project (114.3) -
Acquisition of the North Central Wind Energy Facilities (270.0) -
Other Investing Activities 33.3 52.1
Net Cash Flows Used for Investing Activities (3,229.8) (3,247.6)
FINANCING ACTIVITIES
Issuance of Common Stock 256.9 111.0
Issuance of Long-term Debt 3,055.1 2,431.3
Issuance of Short-term Debt with Original Maturities greater than 90 Days 1,178.5 1,304.5
Change in Short-term Debt with Original Maturities less than 90 Days, Net (437.8) (766.2)
Retirement of Long-term Debt (998.1) (433.2)
Redemption of Short-term Debt with Original Maturities Greater than 90 Days (92.0) (300.0)
Principal Payments for Finance Lease Obligations (30.3) (31.3)
Dividends Paid on Common Stock (746.5) (704.6)
Other Financing Activities (78.5) (38.0)
Net Cash Flows from Financing Activities 2,107.3 1,573.5
Net Increase (Decrease) in Cash and Cash Equivalents (78.6) 72.1
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 438.3 432.6
Cash, Cash Equivalents and Restricted Cash at End of Period $ 359.7 $ 504.7
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 559.9 $ 481.2
Net Cash Paid for Income Taxes 8.6 3.1
Noncash Acquisitions Under Finance Leases 16.3 26.8
Construction Expenditures Included in Current Liabilities as of June 30, 789.3 833.3
Construction Expenditures Included in Noncurrent Liabilities as of June 30, - 8.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, - 22.3
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 0.2 2.2
Noncontrolling Interest Assumed - Dry Lake Solar Project 33.4 -
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
56




AEP TEXAS INC.
AND SUBSIDIARIES

57




AEP TEXAS INC. AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 3,006 3,158 5,824 5,624
Commercial 2,819 2,402 4,893 4,759
Industrial 2,604 2,216 4,484 4,581
Miscellaneous 159 150 296 302
Total Retail 8,588 7,926 15,497 15,266

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 4 6 319 97
Normal - Heating (b) 3 3 188 188
Actual - Cooling (c) 833 936 970 1,167
Normal - Cooling (b) 931 933 1,057 1,058

(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 70 degree temperature base.




58




Second Quarter of 2021 Compared to Second Quarter of 2020
AEP Texas Inc. and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 66.9
Changes in Gross Margin:
Retail Margins 30.7
Margins from Off-system Sales (12.9)
Transmission Revenues 29.5
Other Revenues (47.1)
Total Change in Gross Margin 0.2
Changes in Expenses and Other:
Other Operation and Maintenance (12.3)
Depreciation and Amortization 63.6
Taxes Other Than Income Taxes (5.5)
Interest Income 0.1
Allowance for Equity Funds Used During Construction (1.5)
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (3.1)
Total Change in Expenses and Other 41.2
Income Tax Expense (28.5)
Second Quarter of 2021 $ 79.8

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

Retail Marginsincreased $31 million primarily due to the following:
A $19 million increase in weather-normalized margins primarily in the residential and commercial classes.
A $16 million increase from interim rate increases driven by increased transmission investment.
An $11 million increase from interim rate increases driven by increased distribution investment.
These increases were partially offset by:
A $6 million decrease in weather-related usage primarily due to an 11% decrease in cooling degree days.
A $4 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
Margins from Off-system Sales decreased $13 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
Transmission Revenuesincreased $30 million primarily due to:
A $20 million increase from interim rate increases driven by increased transmission investment.
A $14 million increase due to a prior year one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This increasewas offset in Income Tax Expense below.
These increases were partially offset by:
A $4 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
Other Revenuesdecreased $47 million primarily due to securitization revenues due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
59





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

Other Operation and Maintenanceexpenses increased $12 million primarily due to the following:
A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-system Sales above.
This increase was partially offset by:
A $4 million decrease primarily related to distribution-related expenses.
Depreciation and Amortizationexpenses decreased $64 million primarily due to the following:
A $49 million decrease in securitization amortizations primarily relatedto the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
A $16 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
Taxes Other Than Income Taxesexpenses increased $6 million primarily due to property taxes as a result of increased distribution and transmission investment.
Interest Expense increased $3 million primarily due to higher long-term debt balances.
Income Tax Expenseincreased $29 million primarily due to a decrease in amortization of excess ADIT and an increase in pretax book income. The decrease in amortization of excess ADIT is partially offset above in Gross Margin.
60




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
AEP Texas Inc. and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 114.5
Changes in Gross Margin:
Retail Margins 24.4
Margins from Off-system Sales (43.1)
Transmission Revenues 44.8
Other Revenues (85.3)
Total Change in Gross Margin (59.2)
Changes in Expenses and Other:
Other Operation and Maintenance (15.5)
Depreciation and Amortization 128.6
Taxes Other Than Income Taxes (7.8)
Interest Income (0.3)
Allowance for Equity Funds Used During Construction (2.5)
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (3.6)
Total Change in Expenses and Other 98.8
Income Tax Expense (28.2)
Six Months Ended June 30, 2021 $ 125.9
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals were as follows:

Retail Marginsincreased $24 million primarily due to the following:
A $21 million increase from interim rate increases driven by increased transmission investment.
A $21 million increase from interim rate increases driven by increased distribution investment.
A $13 million increase in weather-related usage primarily due to a 229% increase in heating degree days partially offset by a 17% decrease in cooling degree days.
These increases were partially offset by:
A $19 million decrease due to refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This decrease was partially offset in Income Tax Expense below.
A $6 million decrease in weather-normalized margins primarily in the industrial and residential classes, partially offset by an increase in the commercial class.
Margins from Off-system Sales decreased $43 million primarily due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset in Depreciation and Amortization expenses below.
Transmission Revenues increased $45 million primarily due to the following:
A $39 million increase from interim rate increases driven by increased transmission investment.
A $14 million increase due to a prior year one-time credit to transmission customers as a result of Tax Reform and the most recent base rate case. This increase was offset in Income Tax Expense below.
These increases were partially offset by:
A $9 million decrease due to refunds to customers associated with the most recent base rate case. This decrease was offset in Other Revenues below.
61





Other Revenuesdecreased $85 million primarily due to the following:
A $98 million decrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
This decrease was partially offset by:
A $10 million increase due to refunds to customersassociated withthe most recent base rate case. This increase was partially offset in Retail Margins and Transmission Revenues above.

Expenses and Other and Income Tax Expensechanged between years as follows:

Other Operation and Maintenanceexpenses increased $16 million primarily due to the following:
A $17 million increase due to the prior year revision of the Oklaunion Power Station ARO. This increase was offset in Margins from Off-System Sales above.
A $3 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
These increases were partially offset by:
A $6 million decrease primarily related to distribution-related expenses.
Depreciation and Amortizationexpenses decreased $129 million primarily due to the following:
A $93 million decrease in securitization amortizations primarily relatedto the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. This decrease was offset in Other Revenues above.
A $32 million decrease in depreciation expense due to the retirement of the Oklaunion Power Station in September 2020. This decrease was partially offset above in Margins from Off-system Sales and Other Operation and Maintenance expenses.
Taxes Other Than Income Taxes increased $8 million primarily due to property taxes as a result of increased distribution and transmission investment.
Interest Expense increased $4 million primarily due to higher long-term debt balances.
Income Tax Expenseincreased $28 million primarily due to a decrease in amortization of excess ADIT and an increase in pretax book income. The decrease in amortization of excess ADIT is partially offset above in Gross Margin.
62





AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electric Transmission and Distribution $ 396.6 $ 383.5 $ 758.3 $ 775.1
Sales to AEP Affiliates 1.0 16.9 2.0 48.0
Other Revenues 0.9 1.1 2.4 2.0
TOTAL REVENUES 398.5 401.5 762.7 825.1
EXPENSES
Fuel and Other Consumables Used for Electric Generation - 3.2 - 3.2
Other Operation 109.6 92.9 231.8 210.4
Maintenance 18.7 23.1 37.8 43.7
Depreciation and Amortization 102.0 165.6 199.5 328.1
Taxes Other Than Income Taxes 39.5 34.0 75.8 68.0
TOTAL EXPENSES 269.8 318.8 544.9 653.4
OPERATING INCOME 128.7 82.7 217.8 171.7
Other Income (Expense):
Interest Income 0.2 0.1 0.4 0.7
Allowance for Equity Funds Used During Construction 3.4 4.9 7.5 10.0
Non-Service Cost Components of Net Periodic Benefit Cost 2.7 2.8 5.5 5.6
Interest Expense (45.3) (42.2) (88.3) (84.7)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 89.7 48.3 142.9 103.3
Income Tax Expense (Benefit) 9.9 (18.6) 17.0 (11.2)
NET INCOME $ 79.8 $ 66.9 $ 125.9 $ 114.5
The common stock of AEP Texas is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
63




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 79.8 $ 66.9 $ 125.9 $ 114.5
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.1 and $0.1 for the Six Months Ended June 30, 2021 and 2020, Respectively
0.2 0.2 0.5 0.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively
0.1 0.1 0.1 0.1
TOTAL OTHER COMPREHENSIVE INCOME 0.3 0.3 0.6 0.6
TOTAL COMPREHENSIVE INCOME $ 80.1 $ 67.2 $ 126.5 $ 115.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

64




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2019
$ 1,457.9 $ 1,516.0 $ (12.8) $ 2,961.1
Net Income 47.6 47.6
Other Comprehensive Income 0.3 0.3
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2020
1,457.9 1,563.6 (12.5) 3,009.0
Net Income 66.9 66.9
Other Comprehensive Income 0.3 0.3
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020
$ 1,457.9 $ 1,630.5 $ (12.2) $ 3,076.2
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020
$ 1,457.9 $ 1,757.0 $ (8.9) $ 3,206.0
Net Income 46.1 46.1
Other Comprehensive Income 0.3 0.3
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021
1,457.9 1,803.1 (8.6) 3,252.4
Net Income 79.8 79.8
Other Comprehensive Income 0.3 0.3
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021
$ 1,457.9 $ 1,882.9 $ (8.3) $ 3,332.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

65




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 0.1 $ 0.1
Restricted Cash
(June 30, 2021 and December 31, 2020 Amounts Include $27.9 and $28.7, Respectively, Related to Transition Funding and Restoration Funding)
27.9 28.7
Advances to Affiliates 54.3 7.1
Accounts Receivable:
Customers 141.7 112.8
Affiliated Companies 6.9 5.1
Accrued Unbilled Revenues 82.9 65.8
Miscellaneous 0.1 -
Allowance for Uncollectible Accounts (4.2) (0.1)
Total Accounts Receivable 227.4 183.6
Materials and Supplies 69.5 70.0
Accrued Tax Benefits 4.5 16.8
Prepayments and Other Current Assets 4.3 4.6
TOTAL CURRENT ASSETS 388.0 310.9
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission
5,571.9 5,279.6
Distribution
4,750.8 4,580.8
Other Property, Plant and Equipment 908.9 868.4
Construction Work in Progress 510.0 614.1
Total Property, Plant and Equipment 11,741.6 11,342.9
Accumulated Depreciation and Amortization 1,588.9 1,529.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 10,152.7 9,813.6
OTHER NONCURRENT ASSETS
Regulatory Assets 292.0 266.8
Securitized Assets
(June 30, 2021 and December 31, 2020 Amounts Include $410.4 and $446.8, Respectively, Related to Transition Funding and Restoration Funding)
410.4 446.8
Deferred Charges and Other Noncurrent Assets 240.7 192.1
TOTAL OTHER NONCURRENT ASSETS 943.1 905.7
TOTAL ASSETS $ 11,483.8 $ 11,030.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
66




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ - $ 67.1
Accounts Payable:
General 185.8 231.7
Affiliated Companies 31.1 44.0
Long-term Debt Due Within One Year - Nonaffiliated
(June 30, 2021 and December 31, 2020 Amounts Include $89.8 and $88.7, Respectively, Related to Transition Funding and Restoration Funding)
289.9 88.7
Accrued Taxes 113.4 78.3
Accrued Interest
(June 30, 2021 and December 31, 2020 Amounts Include $2.4 and $2.5, Respectively, Related to Transition Funding and Restoration Funding)
46.2 43.9
Obligations Under Operating Leases 14.2 14.5
Other Current Liabilities 78.5 108.6
TOTAL CURRENT LIABILITIES 759.1 676.8
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated
(June 30, 2021 and December 31, 2020 Amounts Include $362.3 and $403.9, Respectively, Related to Transition Funding and Restoration Funding)
4,936.1 4,731.7
Deferred Income Taxes 1,045.9 1,016.7
Regulatory Liabilities and Deferred Investment Tax Credits 1,273.6 1,270.8
Obligations Under Operating Leases 67.7 71.0
Deferred Credits and Other Noncurrent Liabilities 68.9 57.2
TOTAL NONCURRENT LIABILITIES 7,392.2 7,147.4
TOTAL LIABILITIES 8,151.3 7,824.2
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER'S EQUITY
Paid-in Capital 1,457.9 1,457.9
Retained Earnings 1,882.9 1,757.0
Accumulated Other Comprehensive Income (Loss) (8.3) (8.9)
TOTAL COMMON SHAREHOLDER'S EQUITY 3,332.5 3,206.0
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 11,483.8 $ 11,030.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
67




AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 125.9 $ 114.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 199.5 328.1
Deferred Income Taxes 14.0 (33.9)
Allowance for Equity Funds Used During Construction (7.5) (10.0)
Mark-to-Market of Risk Management Contracts - 0.1
Property Taxes (49.7) (43.2)
Change in Other Noncurrent Assets (42.0) (54.1)
Change in Other Noncurrent Liabilities 17.2 (2.5)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (43.8) (54.1)
Fuel, Materials and Supplies 0.5 (11.4)
Accounts Payable (10.3) 22.1
Accrued Taxes, Net 47.4 79.3
Other Current Assets 0.7 1.6
Other Current Liabilities (29.3) (38.7)
Net Cash Flows from Operating Activities 222.6 297.8
INVESTING ACTIVITIES
Construction Expenditures (531.2) (662.0)
Change in Advances to Affiliates, Net (47.2) 200.0
Other Investing Activities 21.3 17.1
Net Cash Flows Used for Investing Activities (557.1) (444.9)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 444.3 -
Change in Short-term Debt, Net - Nonaffiliated - 2.0
Change in Advances from Affiliates, Net (67.1) 320.4
Retirement of Long-term Debt - Nonaffiliated (40.9) (193.8)
Principal Payments for Finance Lease Obligations (3.3) (3.1)
Other Financing Activities 0.7 0.5
Net Cash Flows from Financing Activities 333.7 126.0
Net Decrease in Cash, Cash Equivalents and Restricted Cash (0.8) (21.1)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 28.8 157.8
Cash, Cash Equivalents and Restricted Cash at End of Period $ 28.0 $ 136.7
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 82.0 $ 74.3
Net Cash Paid (Received) for Income Taxes (9.2) (24.9)
Noncash Acquisitions Under Finance Leases 2.4 4.3
Construction Expenditures Included in Current Liabilities as of June 30, 125.5 192.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
68






AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
69




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Summary of Investment in Transmission Assets for AEPTCo
As of June 30,
2021 2020
(in millions)
Plant In Service $ 10,660.2 $ 8,931.5
Construction Work in Progress 1,393.4 1,613.9
Accumulated Depreciation and Amortization 677.1 488.3
Total Transmission Property, Net $ 11,376.5 $ 10,057.1

Second Quarter of 2021 Compared to Second Quarter of 2020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 73.7
Changes in Transmission Revenues:
Transmission Revenues 127.4
Total Change in Transmission Revenues 127.4
Changes in Expenses and Other:
Other Operation and Maintenance (4.7)
Depreciation and Amortization (13.5)
Taxes Other Than Income Taxes (9.9)
Interest Income (1.2)
Allowance for Equity Funds Used During Construction (1.9)
Interest Expense (1.5)
Total Change in Expenses and Other (32.7)
Income Tax Expense (19.8)
Second Quarter of 2021 $ 148.6

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

Transmission Revenues increased $127 million primarily due to the following:
A $68 million increase due to continued investment in transmission assets.
A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $14 million increase as a result of the non-affiliated annual transmission formula rate true-up.

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

Other Operation and Maintenanceexpenses increased $5 million primarily due to:
A $3 million increase in vegetation management expenses.
A $2 million increase in employee-related expenses.
Depreciation and Amortizationexpenses increased $14 million primarily due to a higher depreciable base.
70




Taxes Other Than Income Taxesincreased $10 million primarily due to higher property taxes as a result of increased transmission investment.
Income Tax Expenseincreased $20 million primarily due to an increase in pretax book income.
71




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
AEP Transmission Company, LLC and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 191.5
Changes in Transmission Revenues:
Transmission Revenues 193.5
Total Change in Transmission Revenues 193.5
Changes in Expenses and Other:
Other Operation and Maintenance (2.4)
Depreciation and Amortization (28.1)
Taxes Other Than Income Taxes (17.3)
Interest Income (1.9)
Allowance for Equity Funds Used During Construction (1.4)
Interest Expense (6.0)
Total Change in Expenses and Other (57.1)
Income Tax Expense (27.6)
Six Months Ended June 30, 2021 $ 300.3

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

Transmission Revenues increased $194 million primarily due to the following:
A $135 million increase due to continued investment in transmission assets.
A $45 million increase as a result of the affiliated annual transmission formula rate true-up which is offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
A $14 million increase as a result of the non-affiliated annual transmission formula rate true-up.

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

Depreciation and Amortizationexpenses increased $28 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxesincreased $17 million primarily due to higher property taxes as a result of increased transmission investment.
Interest Expenseincreased $6 million primarily due to higher long-term debt balances.
Income Tax Expenseincreased $28 million primarily due to an increase in pretax book income.

72






AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Transmission Revenues $ 84.1 $ 60.4 $ 160.1 $ 121.7
Sales to AEP Affiliates 281.4 177.7 567.0 411.4
Other Revenues - - 0.1 0.6
TOTAL REVENUES 365.5 238.1 727.2 533.7
EXPENSES
Other Operation 24.4 22.9 45.5 46.7
Maintenance 3.3 0.1 6.9 3.3
Depreciation and Amortization 72.4 58.9 143.0 114.9
Taxes Other Than Income Taxes 60.1 50.2 117.9 100.6
TOTAL EXPENSES 160.2 132.1 313.3 265.5
OPERATING INCOME 205.3 106.0 413.9 268.2
Other Income (Expense):
Interest Income - Affiliated 0.1 1.3 0.2 2.1
Allowance for Equity Funds Used During Construction 16.6 18.5 33.3 34.7
Interest Expense (34.3) (32.8) (68.4) (62.4)
INCOME BEFORE INCOME TAX EXPENSE 187.7 93.0 379.0 242.6
Income Tax Expense 39.1 19.3 78.7 51.1
NET INCOME $ 148.6 $ 73.7 $ 300.3 $ 191.5
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
73




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Paid-in
Capital
Retained
Earnings
Total
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2019 $ 2,480.6 $ 1,528.9 $ 4,009.5
Capital Contribution from Member 185.0 185.0
Net Income 117.8 117.8
TOTAL MEMBER'S EQUITY - MARCH 31, 2020 2,665.6 1,646.7 4,312.3
Dividends Paid to Member (5.0) (5.0)
Net Income 73.7 73.7
TOTAL MEMBER'S EQUITY - JUNE 30, 2020 $ 2,665.6 $ 1,715.4 $ 4,381.0
TOTAL MEMBER'S EQUITY - DECEMBER 31, 2020 $ 2,765.6 $ 1,947.3 $ 4,712.9
Capital Contribution from Member 124.0 124.0
Net Income 151.7 151.7
TOTAL MEMBER'S EQUITY - MARCH 31, 2021 2,889.6 2,099.0 4,988.6
Capital Contribution from Member 60.0 60.0
Net Income 148.6 148.6
TOTAL MEMBER'S EQUITY - JUNE 30, 2021 $ 2,949.6 $ 2,247.6 $ 5,197.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
74




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Advances to Affiliates $ 113.6 $ 109.1
Accounts Receivable:
Customers 29.7 22.9
Affiliated Companies 96.6 81.2
Total Accounts Receivable 126.3 104.1
Materials and Supplies 9.0 8.5
Prepayments and Other Current Assets 14.6 14.1
TOTAL CURRENT ASSETS 263.5 235.8
TRANSMISSION PROPERTY
Transmission Property 10,278.7 9,593.5
Other Property, Plant and Equipment 381.5 329.5
Construction Work in Progress 1,393.4 1,422.6
Total Transmission Property 12,053.6 11,345.6
Accumulated Depreciation and Amortization 677.1 572.8
TOTAL TRANSMISSION PROPERTY - NET 11,376.5 10,772.8
OTHER NONCURRENT ASSETS
Regulatory Assets 14.8 15.1
Deferred Property Taxes 126.8 220.1
Deferred Charges and Other Noncurrent Assets 8.7 2.2
TOTAL OTHER NONCURRENT ASSETS 150.3 237.4
TOTAL ASSETS $ 11,790.3 $ 11,246.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
75




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER'S EQUITY
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ 265.3 $ 156.7
Accounts Payable:
General 368.4 380.4
Affiliated Companies 70.7 97.3
Long-term Debt Due Within One Year - Nonaffiliated 50.0 50.0
Accrued Taxes 313.4 418.1
Accrued Interest 23.9 23.9
Obligations Under Operating Leases 0.9 1.2
Other Current Liabilities 10.5 9.9
TOTAL CURRENT LIABILITIES 1,103.1 1,137.5
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 3,899.3 3,898.5
Deferred Income Taxes 958.9 906.9
Regulatory Liabilities 620.4 581.8
Obligations Under Operating Leases 0.7 0.4
Deferred Credits and Other Noncurrent Liabilities 10.7 8.0
TOTAL NONCURRENT LIABILITIES 5,490.0 5,395.6
TOTAL LIABILITIES 6,593.1 6,533.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
MEMBER'S EQUITY
Paid-in Capital 2,949.6 2,765.6
Retained Earnings 2,247.6 1,947.3
TOTAL MEMBER'S EQUITY 5,197.2 4,712.9
TOTAL LIABILITIES AND MEMBER'S EQUITY $ 11,790.3 $ 11,246.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
76




AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 300.3 $ 191.5
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 143.0 114.9
Deferred Income Taxes 55.5 22.6
Allowance for Equity Funds Used During Construction (33.3) (34.7)
Property Taxes 93.3 84.3
Change in Other Noncurrent Assets (4.5) (2.6)
Change in Other Noncurrent Liabilities 10.5 30.6
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (22.2) (74.7)
Materials and Supplies (0.5) 0.4
Accounts Payable 0.1 10.5
Accrued Taxes, Net (106.2) (54.7)
Other Current Assets 0.7 0.5
Other Current Liabilities (1.5) 4.5
Net Cash Flows from Operating Activities 435.2 293.1
INVESTING ACTIVITIES
Construction Expenditures (719.7) (825.4)
Change in Advances to Affiliates, Net (4.5) (35.9)
Other Investing Activities (3.4) 1.8
Net Cash Flows Used for Investing Activities (727.6) (859.5)
FINANCING ACTIVITIES
Capital Contributions from Member 184.0 185.0
Issuance of Long-term Debt - Nonaffiliated - 519.4
Change in Advances from Affiliates, Net 108.6 (133.0)
Dividends Paid to Member - (5.0)
Other Financing Activities (0.2) -
Net Cash Flows from Financing Activities 292.4 566.4
Net Change in Cash and Cash Equivalents - -
Cash and Cash Equivalents at Beginning of Period - -
Cash and Cash Equivalents at End of Period $ - $ -
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 66.6 $ 55.8
Net Cash Paid for Income Taxes 21.6 13.5
Construction Expenditures Included in Current Liabilities as of June 30, 267.9 263.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
77






APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
78




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 2,172 2,288 5,867 5,457
Commercial 1,430 1,321 2,887 2,798
Industrial 2,289 2,077 4,367 4,314
Miscellaneous 196 175 396 382
Total Retail 6,087 5,861 13,517 12,951
Wholesale 1,274 1,235 2,222 1,707
Total KWhs 7,361 7,096 15,739 14,658

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 113 144 1,397 1,097
Normal - Heating (b) 87 87 1,402 1,411
Actual - Cooling (c) 381 346 385 366
Normal - Cooling (b) 377 377 383 383

(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.

79




Second Quarter of 2021 Compared to Second Quarter of 2020
Appalachian Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 81.3
Changes in Gross Margin:
Retail Margins 21.4
Margins from Off-system Sales 1.3
Transmission Revenues 7.2
Other Revenues 0.8
Total Change in Gross Margin 30.7
Changes in Expenses and Other:
Other Operation and Maintenance (13.6)
Depreciation and Amortization (14.8)
Taxes Other Than Income Taxes (1.7)
Interest Income (0.2)
Allowance for Equity Funds Used During Construction 1.9
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense 1.2
Total Change in Expenses and Other (27.1)
Income Tax Expense (18.6)
Second Quarter of 2021 $ 66.3

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 Marginsincreased $21 million primarily due to the following:
A $12 million increase in weather-normalized margins driven by increases in the commercial and industrial classes, partially offset by a decrease in the residential class.
A $9 million increase due to rider revenues primarily in West Virginia. This increase was partially offset in other expense items below.
Transmission Revenuesincreased $7 million primarily due to an increase in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.

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

Other Operation and Maintenanceexpenses increased $14 million primarily due to the following:
A $13 million increase in PJM transmission expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
A $3 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
A $2 million increase in transmission vegetation management expenses.
These increases were partially offset by:
A $6 million decrease in accretion expense due to the deferral of incremental Glen Lyn ash pond ARO expense.
Depreciation and Amortizationexpenses increased $15 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Transmission Revenues above.
Income Tax Expense increased $19 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Gross Margin above.
80




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Appalachian Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 196.6
Changes in Gross Margin:
Retail Margins 62.3
Margins from Off-system Sales 2.2
Transmission Revenues 14.2
Other Revenues (0.8)
Total Change in Gross Margin 77.9
Changes in Expenses and Other:
Other Operation and Maintenance (44.9)
Depreciation and Amortization (28.4)
Taxes Other Than Income Taxes (1.5)
Interest Income (0.2)
Allowance for Equity Funds Used During Construction 3.0
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense (0.6)
Total Change in Expenses and Other (72.5)
Income Tax Expense (13.2)
Six Months Ended June 30, 2021 $ 188.8

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 Marginsincreased $62 million primarily due to the following:
A $33 million increase in weather-related usage primarily driven by a 27% increase in heating degree days and 5% increase in cooling degree days.
A $22 million increase due to rider revenue primarily in West Virginia. This increase was partially offset in other expense items below.
Transmission Revenuesincreased $14 million primarily due to an increase in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.

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

Other Operation and Maintenanceexpenses increased $45 million primarily due to the following:
A $23 million increase in distribution vegetation management expenses. This increase was partially offset in Retail Margins above.
A $13 million increase in PJM transmission expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.
An $11 million increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
A $5 million increase in transmission vegetation management expenses.
A $5 million increase due to the current year amortization of regulatory assets related to the 2017-2019 Virginia triennial review which authorized regulatory recovery of previously retired coal-fired generation assets.

81




These increases were partially offset by:
A $7 million decrease in distribution expenses related to storm restoration costs.
A $4 million decrease in accretion expense primarily due to the deferral of incremental Glen Lyn ash pond ARO expense.
Depreciation and Amortizationexpenses increased $28 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Transmission Revenues above.
Income Tax Expenseincreased $13 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Gross Margin above.




82






APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electric Generation, Transmission and Distribution $ 636.5 $ 604.0 $ 1,400.7 $ 1,301.0
Sales to AEP Affiliates 38.1 30.8 88.2 80.5
Other Revenues 2.4 2.7 5.1 5.4
TOTAL REVENUES 677.0 637.5 1,494.0 1,386.9
EXPENSES
Fuel and Other Consumables Used for Electric Generation 137.2 153.9 301.1 264.9
Purchased Electricity for Resale 75.9 50.4 166.0 173.0
Other Operation 118.7 108.8 269.1 242.8
Maintenance 50.1 46.4 115.3 96.7
Depreciation and Amortization 135.4 120.6 271.2 242.8
Taxes Other Than Income Taxes 39.2 37.5 76.9 75.4
TOTAL EXPENSES 556.5 517.6 1,199.6 1,095.6
OPERATING INCOME 120.5 119.9 294.4 291.3
Other Income (Expense):
Interest Income 0.3 0.5 0.6 0.8
Allowance for Equity Funds Used During Construction 4.3 2.4 7.8 4.8
Non-Service Cost Components of Net Periodic Benefit Cost 4.8 4.7 9.5 9.4
Interest Expense (52.9) (54.1) (107.8) (107.2)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 77.0 73.4 204.5 199.1
Income Tax Expense (Benefit) 10.7 (7.9) 15.7 2.5
NET INCOME $ 66.3 $ 81.3 $ 188.8 $ 196.6
The common stock of APCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
83




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 66.3 $ 81.3 $ 188.8 $ 196.6
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $(0.1) and $(0.2) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $2.3 and $(1.3) for Six Months Ended June 30, 2021 and 2020, Respectively
(0.2) (0.8) 8.8 (5.0)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(0.6) and $(0.5) for the Six Months Ended June 30, 2021 and 2020, Respectively
(1.0) (1.0) (2.1) (1.9)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) (1.2) (1.8) 6.7 (6.9)
TOTAL COMPREHENSIVE INCOME $ 65.1 $ 79.5 $ 195.5 $ 189.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
84




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S
EQUITY - DECEMBER 31, 2019
$ 260.4 $ 1,828.7 $ 2,078.3 $ 5.0 $ 4,172.4
Common Stock Dividends (50.0) (50.0)
Net Income 115.3 115.3
Other Comprehensive Loss (5.1) (5.1)
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2020 260.4 1,828.7 2,143.6 (0.1) 4,232.6
Common Stock Dividends (50.0) (50.0)
Net Income 81.3 81.3
Other Comprehensive Loss (1.8) (1.8)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020 $ 260.4 $ 1,828.7 $ 2,174.9 $ (1.9) $ 4,262.1
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020 $ 260.4 $ 1,828.7 $ 2,248.0 $ 7.2 $ 4,344.3
Common Stock Dividends (12.5) (12.5)
Net Income 122.5 122.5
Other Comprehensive Income 7.9 7.9
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 260.4 1,828.7 2,358.0 15.1 4,462.2
Common Stock Dividends (12.5) (12.5)
Net Income 66.3 66.3
Other Comprehensive Loss (1.2) (1.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 $ 260.4 $ 1,828.7 $ 2,411.8 $ 13.9 $ 4,514.8
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.

85




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 3.9 $ 5.8
Restricted Cash for Securitized Funding 19.1 16.9
Advances to Affiliates 91.7 21.4
Accounts Receivable:
Customers 149.7 142.8
Affiliated Companies 63.8 64.3
Accrued Unbilled Revenues 48.9 80.1
Miscellaneous 2.2 0.3
Allowance for Uncollectible Accounts (2.3) (3.1)
Total Accounts Receivable 262.3 284.4
Fuel 145.3 193.6
Materials and Supplies 102.5 99.6
Risk Management Assets 37.1 22.4
Regulatory Asset for Under-Recovered Fuel Costs 26.4 5.3
Prepayments and Other Current Assets 59.6 24.7
TOTAL CURRENT ASSETS 747.9 674.1
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 6,653.9 6,633.7
Transmission 4,004.8 3,900.5
Distribution 4,563.2 4,464.3
Other Property, Plant and Equipment 663.7 627.2
Construction Work in Progress 529.7 484.6
Total Property, Plant and Equipment 16,415.3 16,110.3
Accumulated Depreciation and Amortization 4,888.8 4,716.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 11,526.5 11,394.1
OTHER NONCURRENT ASSETS
Regulatory Assets 830.4 686.3
Securitized Assets 197.6 210.1
Employee Benefits and Pension Assets 154.5 150.1
Operating Lease Assets 74.0 78.8
Deferred Charges and Other Noncurrent Assets 115.8 121.7
TOTAL OTHER NONCURRENT ASSETS 1,372.3 1,247.0
TOTAL ASSETS $ 13,646.7 $ 13,315.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
86




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
June 30, December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ - $ 18.6
Accounts Payable:
General 219.0 212.0
Affiliated Companies 81.4 97.1
Long-term Debt Due Within One Year - Nonaffiliated 380.4 518.3
Customer Deposits 72.0 77.8
Accrued Taxes 109.3 109.9
Accrued Interest 48.8 49.9
Obligations Under Operating Leases 15.1 14.9
Other Current Liabilities 108.8 119.2
TOTAL CURRENT LIABILITIES 1,034.8 1,217.7
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 4,569.4 4,315.8
Deferred Income Taxes 1,739.4 1,749.9
Regulatory Liabilities and Deferred Investment Tax Credits 1,251.3 1,224.7
Asset Retirement Obligations 385.8 304.8
Employee Benefits and Pension Obligations 43.7 44.0
Obligations Under Operating Leases 59.5 64.4
Deferred Credits and Other Noncurrent Liabilities 48.0 49.6
TOTAL NONCURRENT LIABILITIES 8,097.1 7,753.2
TOTAL LIABILITIES 9,131.9 8,970.9
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER'S EQUITY
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares
260.4 260.4
Paid-in Capital 1,828.7 1,828.7
Retained Earnings 2,411.8 2,248.0
Accumulated Other Comprehensive Income (Loss) 13.9 7.2
TOTAL COMMON SHAREHOLDER'S EQUITY 4,514.8 4,344.3
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 13,646.7 $ 13,315.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
87




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 188.8 $ 196.6
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 271.2 242.8
Deferred Income Taxes 4.0 (11.8)
Allowance for Equity Funds Used During Construction (7.8) (4.8)
Mark-to-Market of Risk Management Contracts (16.8) 1.5
Deferred Fuel Over/Under-Recovery, Net (21.1) 30.9
Change in Other Noncurrent Assets (70.2) (11.1)
Change in Other Noncurrent Liabilities 12.5 (21.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net 23.7 (37.3)
Fuel, Materials and Supplies 45.4 (2.2)
Accounts Payable (3.9) (69.6)
Accrued Taxes, Net (26.6) 8.9
Other Current Assets (8.8) 18.8
Other Current Liabilities (23.0) (29.7)
Net Cash Flows from Operating Activities 367.4 311.7
INVESTING ACTIVITIES
Construction Expenditures (374.8) (400.2)
Change in Advances to Affiliates, Net (70.3) (60.2)
Other Investing Activities 11.1 3.9
Net Cash Flows Used for Investing Activities (434.0) (456.5)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 494.0 492.2
Change in Advances from Affiliates, Net (18.6) (236.7)
Retirement of Long-term Debt - Nonaffiliated (380.0) (12.2)
Principal Payments for Finance Lease Obligations (3.9) (3.6)
Dividends Paid on Common Stock (25.0) (100.0)
Other Financing Activities 0.4 0.1
Net Cash Flows from Financing Activities 66.9 139.8
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash for Securitized Funding 0.3 (5.0)
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period 22.7 26.8
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period $ 23.0 $ 21.8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 104.7 $ 101.8
Net Cash Paid for Income Taxes 35.8 7.4
Noncash Acquisitions Under Finance Leases 0.9 2.2
Construction Expenditures Included in Current Liabilities as of June 30, 98.0 97.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
88






INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
89




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 1,181 1,244 2,713 2,699
Commercial 1,136 1,021 2,214 2,143
Industrial 1,887 1,630 3,689 3,475
Miscellaneous 12 15 29 33
Total Retail 4,216 3,910 8,645 8,350
Wholesale 1,500 2,323 3,445 4,016
Total KWhs 5,716 6,233 12,090 12,366

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 285 343 2,341 2,179
Normal - Heating (b) 238 237 2,408 2,419
Actual - Cooling (c) 325 286 325 286
Normal - Cooling (b) 266 263 267 265

(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.
90




Second Quarter of 2021 Compared to Second Quarter of 2020
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 63.8
Changes in Gross Margin:
Retail Margins 28.8
Margins from Off-system Sales 0.1
Transmission Revenues (4.4)
Other Revenues (2.1)
Total Change in Gross Margin 22.4
Changes in Expenses and Other:
Other Operation and Maintenance (30.9)
Depreciation and Amortization (3.7)
Taxes Other Than Income Taxes (4.1)
Other Income 0.3
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (1.0)
Total Change in Expenses and Other (39.5)
Income Tax Expense 10.5
Second Quarter of 2021 $ 57.2

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 Marginsincreased $29 million primarily due to the following:
A $36 million increase due to wholesale true-up, increase in rider revenues and the Indiana base rate case. This increase was partially offset in other expense items below.
A $3 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
A $10 million decrease in weather-normalized retail margins.
A $7 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
Transmission Revenuesdecreased $4 million primarily due to the annual transmission formula rate true-up.

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

Other Operation and Maintenanceexpenses increased $31 million primarily due to the following:
A $17 million increase in transmission expenses primarily due to an $11 million increase in vegetation management expenses and a $6 million increase as a result of the annual transmission formula rate true up.
A $9 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
A $6 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
These increases were partially offset by:
A $5 million decrease in customer service and information expenses primarily due to an Indiana order to refund an over collection of Demand Side Management expenses. This decrease was offset in Retail Margins above.
A $3 million decrease in Cook Plant refueling outage expenses.
91




Depreciation and Amortization expenses increased $4 million primarily due to a higher depreciable base. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxesincreased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
Income Tax Expense decreased $11 million primarily due to a decrease in pretax book income, an increase in flow through tax benefits and a decrease in state tax expense.
92




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Indiana Michigan Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 156.1
Changes in Gross Margin:
Retail Margins 26.2
Margins from Off-system Sales (0.2)
Transmission Revenues (5.0)
Other Revenues (0.1)
Total Change in Gross Margin 20.9
Changes in Expenses and Other:
Other Operation and Maintenance (40.7)
Depreciation and Amortization (19.0)
Taxes Other Than Income Taxes (3.9)
Other Income 0.8
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense 2.4
Total Change in Expenses and Other (60.6)
Income Tax Expense 11.6
Six Months Ended June 30, 2021 $ 128.0

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 Marginsincreased $26 million primarily due to the following:
A $48 million increase due to wholesale true-up, Indiana and Michigan base rate cases and increases in rider revenues. This increase was partially offset in other expense items below.
A $10 million increase in weather-related usage primarily due to a 12% increase in heating degree days and a 14% increase in cooling degree days.
A $3 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
A $23 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
A $17 million decrease in weather-normalized retail margins.
Transmission Revenuesdecreased $5 million primarily due to the annual transmission formula rate true-up.


93




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

Other Operation and Maintenanceexpenses increased $41 million primarily due to the following:
An $18 million increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
A $17 million increase in transmission expenses primarily due to an $11 million increase in vegetation management expenses and a $6 million increase as a result of the annual transmission formula rate true-up.
A $6 million increase in employee-related expenses.
A $6 million increase in distribution expenses primarily due to an increase in vegetation management expenses.
A $4 million increase due to a decreased Nuclear Electric Insurance Limited distribution in 2021.
These increases were partially offset by:
A $10 million decrease in customer service and information expenses primarily due to an Indiana order to refund an over collection of Demand Side Management expenses. This decrease was offset in Retail Margins above.
A $6 million decrease in Cook Plant refueling outage expenses.
Depreciation and Amortization expenses increased $19 million primarily due to a higher depreciable base and an increase in depreciation rates. This increase was partially offset in Retail Margins above.
Taxes Other Than Income Taxes increased $4 million primarily due to property taxes driven by an increase in utility plant and higher tax rates.
Income Tax Expensedecreased $12 million primarily due to a decrease in pretax book income and a decrease in state tax expense.
94





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electric Generation, Transmission and Distribution $ 569.2 $ 524.9 $ 1,116.9 $ 1,078.3
Sales to AEP Affiliates 0.7 4.9 1.5 7.8
Other Revenues - Affiliated 12.2 15.8 26.5 28.3
Other Revenues - Nonaffiliated 1.7 1.0 3.4 2.5
TOTAL REVENUES 583.8 546.6 1,148.3 1,116.9
EXPENSES
Fuel and Other Consumables Used for Electric Generation 49.9 48.4 86.2 101.6
Purchased Electricity for Resale 39.7 40.5 87.0 90.6
Purchased Electricity from AEP Affiliates 57.8 43.7 109.4 79.9
Other Operation 160.3 149.5 314.9 294.2
Maintenance 64.4 44.3 113.4 93.4
Depreciation and Amortization 108.9 105.2 218.1 199.1
Taxes Other Than Income Taxes 29.8 25.7 56.0 52.1
TOTAL EXPENSES 510.8 457.3 985.0 910.9
OPERATING INCOME 73.0 89.3 163.3 206.0
Other Income (Expense):
Other Income 3.4 3.1 6.4 5.6
Non-Service Cost Components of Net Periodic Benefit Cost 4.1 4.2 8.2 8.4
Interest Expense (29.1) (28.1) (56.4) (58.8)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 51.4 68.5 121.5 161.2
Income Tax Expense (Benefit) (5.8) 4.7 (6.5) 5.1
NET INCOME $ 57.2 $ 63.8 $ 128.0 $ 156.1
The common stock of I&M is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
95




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 57.2 $ 63.8 $ 128.0 $ 156.1
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2021 and 2020, Respectively
0.4 0.4 0.9 0.8
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively
(0.1) - (0.1) -
TOTAL OTHER COMPREHENSIVE INCOME 0.3 0.4 0.8 0.8
TOTAL COMPREHENSIVE INCOME $ 57.5 $ 64.2 $ 128.8 $ 156.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
96




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2019
$ 56.6 $ 980.9 $ 1,518.5 $ (11.6) $ 2,544.4
Common Stock Dividends (21.3) (21.3)
ASU 2016-13 Adoption 0.4 0.4
Net Income 92.3 92.3
Other Comprehensive Income 0.4 0.4
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2020 56.6 980.9 1,589.9 (11.2) 2,616.2
Common Stock Dividends (21.2) (21.2)
Net Income 63.8 63.8
Other Comprehensive Income 0.4 0.4
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020 $ 56.6 $ 980.9 $ 1,632.5 $ (10.8) $ 2,659.2
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020
$ 56.6 $ 980.9 $ 1,718.7 $ (7.0) $ 2,749.2
Common Stock Dividends (25.0) (25.0)
Net Income 70.8 70.8
Other Comprehensive Income 0.5 0.5
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 56.6 980.9 1,764.5 (6.5) 2,795.5
Common Stock Dividends (75.0) (75.0)
Net Income 57.2 57.2
Other Comprehensive Income 0.3 0.3
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 $ 56.6 $ 980.9 $ 1,746.7 $ (6.2) $ 2,778.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
97




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 2.5 $ 3.3
Advances to Affiliates 99.9 13.3
Accounts Receivable:
Customers 50.7 44.0
Affiliated Companies 43.5 51.3
Accrued Unbilled Revenues 2.5 -
Miscellaneous 1.9 2.0
Allowance for Uncollectible Accounts (0.2) (0.3)
Total Accounts Receivable 98.4 97.0
Fuel 63.8 86.0
Materials and Supplies 171.0 175.8
Risk Management Assets 7.7 3.6
Accrued Tax Benefits 6.6 10.3
Regulatory Asset for Under-Recovered Fuel Costs 5.6 5.4
Prepayments and Other Current Assets 20.8 24.1
TOTAL CURRENT ASSETS 476.3 418.8
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 5,324.7 5,264.7
Transmission 1,727.0 1,696.4
Distribution 2,680.8 2,594.6
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) 699.4 686.7
Construction Work in Progress 368.4 362.4
Total Property, Plant and Equipment 10,800.3 10,604.8
Accumulated Depreciation, Depletion and Amortization 3,726.9 3,552.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,073.4 7,052.3
OTHER NONCURRENT ASSETS
Regulatory Assets 433.1 404.8
Spent Nuclear Fuel and Decommissioning Trusts 3,612.4 3,306.7
Operating Lease Assets 175.9 218.1
Deferred Charges and Other Noncurrent Assets 226.5 237.6
TOTAL OTHER NONCURRENT ASSETS 4,447.9 4,167.2
TOTAL ASSETS $ 11,997.6 $ 11,638.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
98




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2021 and December 31, 2020
(dollars in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT LIABILITIES
Advances from Affiliates $ - $ 103.0
Accounts Payable:
General 143.3 153.2
Affiliated Companies 74.2 80.5
Long-term Debt Due Within One Year - Nonaffiliated
(June 30, 2021 and December 31, 2020 Amounts Include $60.9 and $75.7,
Respectively, Related to DCC Fuel)
140.2 369.6
Risk Management Liabilities 1.1 0.1
Customer Deposits 39.9 41.7
Accrued Taxes 93.5 102.5
Accrued Interest 37.7 35.6
Obligations Under Operating Leases 86.5 85.6
Regulatory Liability for Over-Recovered Fuel Costs 15.2 20.8
Other Current Liabilities 88.6 111.9
TOTAL CURRENT LIABILITIES 720.2 1,104.5
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 3,114.8 2,660.3
Deferred Income Taxes 1,093.4 1,064.4
Regulatory Liabilities and Deferred Investment Tax Credits 2,251.4 2,041.9
Asset Retirement Obligations 1,849.3 1,812.9
Obligations Under Operating Leases 91.9 135.9
Deferred Credits and Other Noncurrent Liabilities 98.6 69.2
TOTAL NONCURRENT LIABILITIES 8,499.4 7,784.6
TOTAL LIABILITIES 9,219.6 8,889.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER'S EQUITY
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares
56.6 56.6
Paid-in Capital 980.9 980.9
Retained Earnings 1,746.7 1,718.7
Accumulated Other Comprehensive Income (Loss) (6.2) (7.0)
TOTAL COMMON SHAREHOLDER'S EQUITY 2,778.0 2,749.2
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 11,997.6 $ 11,638.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
99




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 128.0 $ 156.1
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 218.1 199.1
Rockport Plant, Unit 2 Operating Lease Amortization 33.9 34.6
Deferred Income Taxes (8.2) (47.1)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net (14.3) 28.4
Allowance for Equity Funds Used During Construction (7.0) (4.8)
Mark-to-Market of Risk Management Contracts (3.1) 3.2
Amortization of Nuclear Fuel 40.4 45.6
Deferred Fuel Over/Under-Recovery, Net (5.7) 26.9
Change in Other Noncurrent Assets 11.7 16.1
Change in Other Noncurrent Liabilities 26.2 33.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (0.4) (18.1)
Fuel, Materials and Supplies 27.1 (26.9)
Accounts Payable 16.4 (33.7)
Accrued Taxes, Net (5.3) 2.7
Rockport Plant, Unit 2 Operating Lease Payments (36.9) (36.9)
Other Current Assets 2.0 9.7
Other Current Liabilities (29.1) (44.5)
Net Cash Flows from Operating Activities 393.8 343.6
INVESTING ACTIVITIES
Construction Expenditures (241.0) (267.6)
Change in Advances to Affiliates, Net (86.6) (0.1)
Purchases of Investment Securities (1,149.7) (971.4)
Sales of Investment Securities 1,122.7 940.5
Acquisitions of Nuclear Fuel (63.0) (37.7)
Other Investing Activities 4.5 6.2
Net Cash Flows Used for Investing Activities (413.1) (330.1)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 507.0 -
Change in Advances from Affiliates, Net (103.0) 79.7
Retirement of Long-term Debt - Nonaffiliated (282.7) (47.6)
Principal Payments for Finance Lease Obligations (3.3) (3.3)
Dividends Paid on Common Stock (100.0) (42.5)
Other Financing Activities 0.5 0.2
Net Cash Flows from (Used for) Financing Activities 18.5 (13.5)
Net Decrease in Cash and Cash Equivalents (0.8) -
Cash and Cash Equivalents at Beginning of Period 3.3 2.0
Cash and Cash Equivalents at End of Period $ 2.5 $ 2.0
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 52.1 $ 55.6
Net Cash Paid for Income Taxes 4.1 48.0
Noncash Acquisitions Under Finance Leases 2.8 1.6
Construction Expenditures Included in Current Liabilities as of June 30, 59.9 69.9
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, - 22.3
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage 0.2 2.2
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
100






OHIO POWER COMPANY AND SUBSIDIARIES

101




OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 3,059 3,141 7,165 6,975
Commercial 3,668 3,157 7,170 6,673
Industrial 3,735 2,932 7,136 6,475
Miscellaneous 26 30 55 60
Total Retail (a) 10,488 9,260 21,526 20,183
Wholesale (b) 445 455 1,048 845
Total KWhs 10,933 9,715 22,574 21,028

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

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 215 292 1,992 1,765
Normal - Heating (b) 183 182 2,066 2,080
Actual - Cooling (c) 361 314 361 317
Normal - Cooling (b) 304 301 307 304

(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.
102




Second Quarter of 2021 Compared to Second Quarter of 2020
Ohio Power Company and Subsidiaries
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 80.9
Changes in Gross Margin:
Retail Margins 45.8
Margins from Off-system Sales (13.3)
Transmission Revenues 0.5
Other Revenues 7.7
Total Change in Gross Margin 40.7
Changes in Expenses and Other:
Other Operation and Maintenance (18.1)
Depreciation and Amortization (16.8)
Taxes Other Than Income Taxes (10.9)
Interest Income (0.1)
Carrying Costs Income (0.1)
Allowance for Equity Funds Used During Construction 0.1
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (1.6)
Total Change in Expenses and Other (47.6)
Income Tax Expense -
Second Quarter of 2021 $ 74.0

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

Retail Marginsincreased $46 million primarily due to the following:
A $30 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $19 million increase in usage primarily from the commercial and residential classes of $11 million and $6 million, respectively.
A $12 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This decrease was offset in Other Operation and Maintenance expenses below.
A $7 million increase in the Legacy Generation Resource Rider (LGRR). This increase was offset in Margins from Off-system Sales and Other Revenues below.
A $5 million increase in revenues associated with a vegetation management rider. This increase was partially offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $19 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
An $11 million decrease in revenues associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.
Margins from Off-system Salesdecreased $13 million primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
103




Other Revenuesincreased $8 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.

Expenses and Other changed between years as follows:

Other Operation and Maintenanceexpenses increased $18 million primarily due to the following:
A $26 million increase in recoverable PJM expense. This increase was partially offset in Retail Margins above.
A $9 million increase in PJM expenses primarily related to the annual formula rate true-up.
An $8 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in retail margins.
A $5 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
These increases were partially offset by:
An $11 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
A $9 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
A $7 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
Depreciation and Amortization expenses increased $17 million primarily due to the following:
A $6 million increase in recoverable DIR depreciable expense. This increase was partially offset in Retail Margins above.
A $5 million increase in amortization of plant primarily related to capitalized software.
A $3 million increase in depreciation expense due to a higher depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $11 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
104




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Ohio Power Company and Subsidiaries
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 156.0
Changes in Gross Margin:
Retail Margins 76.9
Margins from Off-system Sales (27.3)
Transmission Revenues (2.3)
Other Revenues 13.1
Total Change in Gross Margin 60.4
Changes in Expenses and Other:
Other Operation and Maintenance (32.5)
Depreciation and Amortization (21.4)
Taxes Other Than Income Taxes (20.2)
Interest Income (0.1)
Allowance for Equity Funds Used During Construction 0.9
Non-Service Cost Components of Net Periodic Benefit Cost (0.2)
Interest Expense (4.3)
Total Change in Expenses and Other (77.8)
Income Tax Expense 3.6
Six Months Ended June 30, 2021 $ 142.2

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

Retail Marginsincreased $77 million primarily due to the following:
An $88 million net increase in Basic Transmission Cost Rider revenues and recoverable PJM expenses. This increase was partially offset in Other Operation and Maintenance expenses below.
A $19 million increase in usage from the commercial and residential classes of $11 million and $8 million, respectively.
A $17 million increase in rider revenues associated with the DIR. This increase was partially offset in other expense items below.
A $15 million increase in the LGRR. This increase was offset in Margins from Off-system Sales and Other Revenues below.
A $10 million increase in revenues associated with a vegetation management rider. This increase was partially offset in Other Operation and Maintenance expenses below.
An $8 million increase due to a PUCO order to refund unused 2018 major storm reserve collections to customers in the prior period. This increase was offset in Other Operation and Maintenance expenses below.
These increases were partially offset by:
A $46 million decrease due to the ending of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
A $27 million decrease in revenues associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
Margins from Off-system Sales decreased $27 million primarily due to unfavorable deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
Other Revenues increased $13 million primarily due to third-party LGRR revenue related to the recovery of OVEC costs. This increase was offset in Retail Margins and Margins from Off-system Sales above.
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Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenanceexpenses increased $33 million primarily due to the following:
A $78 million increase in recoverable PJM expense. This increase was partially offset in Retail Margins above.
A $10 million increase in recoverable distribution expenses related to vegetation management. This increase was offset in Retail Margins above.
A $9 million increase in PJM expenses primarily related to the annual formula rate true-up.
An $8 million increase in distribution maintenance expenses related to the annual major storm reserve true-up. This increase was offset in retail margins.
These increases were partially offset by:
A $30 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
A $27 million decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decrease was offset in Retail Margins above.
A $14 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
Depreciation and Amortization expenses increased $21 million primarily due to the following:
An $8 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
A $6 million increase in recoverable DIR depreciation expense. This increase was partially offset in Retail Margins above.
A $6 million increase in amortization of plant primarily related to capitalized software.
Taxes Other Than Income Taxes increased $20 million primarily due to property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
Interest Expenseincreased $4 million primarily due to higher long-term debt balances.
Income Tax Expensedecreased $4 million due to a decrease in pretax book income.
106





OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electricity, Transmission and Distribution $ 690.1 $ 621.8 $ 1,406.8 $ 1,301.0
Sales to AEP Affiliates 12.8 16.3 17.6 24.7
Other Revenues 2.0 2.3 4.4 5.0
TOTAL REVENUES 704.9 640.4 1,428.8 1,330.7
EXPENSES
Purchased Electricity for Resale 153.6 113.9 328.9 263.0
Purchased Electricity from AEP Affiliates 14.4 30.3 44.5 72.7
Other Operation 193.2 186.6 377.8 363.9
Maintenance 38.4 26.9 77.1 58.5
Depreciation and Amortization 76.6 59.8 151.7 130.3
Taxes Other Than Income Taxes 118.9 108.0 240.2 220.0
TOTAL EXPENSES 595.1 525.5 1,220.2 1,108.4
OPERATING INCOME 109.8 114.9 208.6 222.3
Other Income (Expense):
Interest Income 0.1 0.2 0.3 0.4
Carrying Costs Income 0.5 0.6 1.0 1.0
Allowance for Equity Funds Used During Construction 2.9 2.8 5.6 4.7
Non-Service Cost Components of Net Periodic Benefit Cost 3.6 3.7 7.3 7.5
Interest Expense (31.7) (30.1) (63.3) (59.0)
INCOME BEFORE INCOME TAX EXPENSE 85.2 92.1 159.5 176.9
Income Tax Expense 11.2 11.2 17.3 20.9
NET INCOME $ 74.0 $ 80.9 $ 142.2 $ 156.0
The common stock of OPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
107




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 74.0 $ 80.9 $ 142.2 $ 156.0
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $0 for the Six Months Ended June 30, 2021 and 2020, Respectively
- - - -
TOTAL COMPREHENSIVE INCOME $ 74.0 $ 80.9 $ 142.2 $ 156.0
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
108




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2019
$ 321.2 $ 838.8 $ 1,348.5 $ - $ 2,508.5
Common Stock Dividends (21.9) (21.9)
ASU 2016-13 Adoption 0.3 0.3
Net Income 75.1 75.1
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2020
321.2 838.8 1,402.0 - 2,562.0
Common Stock Dividends (21.9) (21.9)
Net Income 80.9 80.9
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020
$ 321.2 $ 838.8 $ 1,461.0 $ - $ 2,621.0
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020
$ 321.2 $ 838.8 $ 1,532.7 $ - $ 2,692.7
Common Stock Dividends (21.9) (21.9)
Net Income 68.2 68.2
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021
321.2 838.8 1,579.0 - 2,739.0
Common Stock Dividends (21.9) (21.9)
Net Income 74.0 74.0
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021
$ 321.2 $ 838.8 $ 1,631.1 $ - $ 2,791.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
109




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 5.8 $ 7.4
Accounts Receivable:
Customers 86.1 50.0
Affiliated Companies 74.7 65.1
Accrued Unbilled Revenues 16.4 14.8
Miscellaneous 7.1 3.9
Allowance for Uncollectible Accounts (0.7) (0.6)
Total Accounts Receivable 183.6 133.2
Materials and Supplies 68.8 66.9
Renewable Energy Credits 31.7 29.5
Prepayments and Other Current Assets 23.7 19.3
TOTAL CURRENT ASSETS 313.6 256.3
PROPERTY, PLANT AND EQUIPMENT
Electric:
Transmission 2,901.5 2,831.9
Distribution 5,889.8 5,708.3
Other Property, Plant and Equipment 959.8 899.6
Construction Work in Progress 341.1 362.3
Total Property, Plant and Equipment 10,092.2 9,802.1
Accumulated Depreciation and Amortization 2,416.0 2,350.0
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,676.2 7,452.1
OTHER NONCURRENT ASSETS
Regulatory Assets 399.7 385.8
Operating Lease Assets 86.6 92.0
Deferred Charges and Other Noncurrent Assets 383.9 524.2
TOTAL OTHER NONCURRENT ASSETS 870.2 1,002.0
TOTAL ASSETS $ 8,860.0 $ 8,710.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
110




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
June 30, December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 56.3 $ 259.2
Accounts Payable:
General 186.9 181.0
Affiliated Companies 95.6 118.4
Long-term Debt Due Within One Year - Nonaffiliated 500.1 500.1
Risk Management Liabilities 7.3 8.7
Customer Deposits 76.7 55.1
Accrued Taxes 413.9 631.0
Obligations Under Operating Leases 13.1 13.1
Other Current Liabilities 131.0 139.6
TOTAL CURRENT LIABILITIES 1,480.9 1,906.2
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 2,376.7 1,930.1
Long-term Risk Management Liabilities 98.2 101.6
Deferred Income Taxes 994.5 955.1
Regulatory Liabilities and Deferred Investment Tax Credits 999.3 1,005.2
Obligations Under Operating Leases 74.1 79.5
Deferred Credits and Other Noncurrent Liabilities 45.2 40.0
TOTAL NONCURRENT LIABILITIES 4,588.0 4,111.5
TOTAL LIABILITIES 6,068.9 6,017.7
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER'S EQUITY
Common Stock -No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares
321.2 321.2
Paid-in Capital 838.8 838.8
Retained Earnings 1,631.1 1,532.7
TOTAL COMMON SHAREHOLDER'S EQUITY 2,791.1 2,692.7
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 8,860.0 $ 8,710.4
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
111




OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 142.2 $ 156.0
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 151.7 130.3
Deferred Income Taxes 21.5 21.6
Allowance for Equity Funds Used During Construction (5.6) (4.7)
Mark-to-Market of Risk Management Contracts (4.8) 13.9
Property Taxes 154.2 151.4
Change in Other Noncurrent Assets (45.8) (103.2)
Change in Other Noncurrent Liabilities 7.2 (45.4)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (47.9) (14.1)
Materials and Supplies (3.0) (16.8)
Accounts Payable (13.6) (23.1)
Accrued Taxes, Net (222.8) (150.8)
Other Current Assets 0.8 3.1
Other Current Liabilities 13.9 (25.7)
Net Cash Flows from Operating Activities 148.0 92.5
INVESTING ACTIVITIES
Construction Expenditures (353.3) (416.7)
Other Investing Activities 6.6 10.3
Net Cash Flows Used for Investing Activities (346.7) (406.4)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated 445.8 347.0
Change in Advances from Affiliates, Net (202.9) 12.1
Retirement of Long-term Debt - Nonaffiliated (0.1) -
Principal Payments for Finance Lease Obligations (2.4) (2.4)
Dividends Paid on Common Stock (43.8) (43.8)
Other Financing Activities 0.5 0.6
Net Cash Flows from Financing Activities 197.1 313.5
Net Decrease in Cash and Cash Equivalents (1.6) (0.4)
Cash and Cash Equivalents at Beginning of Period 7.4 3.7
Cash and Cash Equivalents at End of Period $ 5.8 $ 3.3
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 58.4 $ 54.1
Net Cash Paid for Income Taxes 1.3 2.4
Noncash Acquisitions Under Finance Leases 0.9 4.9
Construction Expenditures Included in Current Liabilities as of June 30, 70.9 74.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
112






PUBLIC SERVICE COMPANY OF OKLAHOMA
113




PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 1,312 1,457 2,889 2,819
Commercial 1,255 1,136 2,305 2,191
Industrial 1,513 1,401 2,817 2,838
Miscellaneous 310 293 580 565
Total Retail 4,390 4,287 8,591 8,413
Wholesale 121 78 188 131
Total KWhs 4,511 4,365 8,779 8,544

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 45 74 1,195 873
Normal - Heating (b) 44 43 1,077 1,077
Actual - Cooling (c) 577 672 584 705
Normal - Cooling (b) 658 659 675 676

(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.
114




Second Quarter of 2021 Compared to Second Quarter of 2020
Public Service Company of Oklahoma
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Net Income
(in millions)
Second Quarter of 2020 $ 46.4
Changes in Gross Margin:
Retail Margins (a) 13.1
Margins from Off-system Sales (0.2)
Transmission Revenues 2.2
Other Revenues (5.8)
Total Change in Gross Margin 9.3
Changes in Expenses and Other:
Other Operation and Maintenance (9.6)
Depreciation and Amortization (5.2)
Taxes Other Than Income Taxes (0.1)
Interest Income 1.6
Allowance for Equity Funds Used During Construction (0.3)
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense 1.4
Total Change in Expenses and Other (12.1)
Income Tax Expense 2.5
Second Quarter of 2021 $ 46.1

(a)Includes firm wholesale sales to municipals and cooperatives.

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 Marginsincreased $13 million primarily due to the following:
A $17 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
A $5 million increase in weather-normalized retail margins.
These increases were partially offset by:
A $6 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days and a 39% decrease in heating degree days.
A $3 million increase in fuel expense due to production tax credits passed back to customers. This increase is offset in Income Tax Expense.
Other Revenuesdecreased $6 million primarily due to business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other changed between years as follows:

Other Operation and Maintenanceexpenses increased $10 million primarily due to the following:
A $10 million increase in transmission expenses primarily due to a $6 million increase as a result of the annual transmission formula rate true-up and a $4 million increase in recoverable SPP expense. These increases were partially offset in Retail Margins above.
A $4 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
115





These increases were partially offset by:
A $4 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
A $3 million decrease in distribution expenses primarily due to a decrease in overhead line maintenance.
Depreciation and Amortization increased $5 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
116




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Public Service Company of Oklahoma
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Net Income
(in millions)
Six Months Ended June 30, 2020 $ 36.1
Changes in Gross Margin:
Retail Margins (a) 17.2
Margin from Off-system Sales (0.3)
Transmission Revenues 3.2
Other Revenues (5.6)
Total Change in Gross Margin 14.5
Changes in Expenses and Other:
Other Operation and Maintenance (1.5)
Depreciation and Amortization (10.4)
Taxes Other Than Income Taxes (1.3)
Interest Income 1.6
Allowance for Equity Funds Used During Construction (0.9)
Non-Service Cost Components of Net Periodic Benefit Cost 0.1
Interest Expense 2.8
Total Change in Expenses and Other (9.6)
Income Tax Expense 2.4
Six Months Ended June 30, 2021 $ 43.4
(a)Includes firm wholesale sales to municipals and cooperatives.

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 Marginsincreased $17 million primarily due to the following:
A $19 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
A $4 million increase in weather-normalized retail margins.
These increases were partially offset by:
A $3 million decrease in weather-related usage primarily due to a 17% decrease in cooling degree days partially offset by a 37% increase in heating degree days.
A $3 million increase in fuel expense due to production tax credits passed back to customers. This increase is offset in Income Tax Expense.
Transmission Revenuesincreased $3 million primarily due to the annual transmission formula rate true-up.
Other Revenuesdecreased $6 million primarily due to business development revenue. This decrease was partially offset in Other Operation and Maintenance expenses below.

Expenses and Other changed between years as follows:

Other Operation and Maintenanceexpenses increased $2 million primarily due to the following:
A $9 million increase in transmission expenses primarily due to a $6 million increase as a result of the annual transmission formula rate true-up and a $3 million increase in recoverable SPP expense. These increases were partially offset in Retail Margins above.
A $3 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.

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These increases were partially offset by:
An $8 million decrease in distribution expenses primarily due to a decrease in overhead line maintenance.
A $4 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
Depreciation and Amortizationexpenses increased $10 million primarily due to a higher depreciable base and the timing of refunds to customers under rate rider mechanisms.
118





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electric Generation, Transmission and Distribution $ 342.5 $ 301.1 $ 636.1 $ 596.5
Sales to AEP Affiliates 1.1 1.3 2.1 2.4
Other Revenues 0.9 6.2 2.4 7.0
TOTAL REVENUES 344.5 308.6 640.6 605.9
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 124.0 97.4 244.9 224.7
Other Operation 81.3 69.6 160.4 156.8
Maintenance 22.5 24.6 46.9 49.0
Depreciation and Amortization 50.2 45.0 100.1 89.7
Taxes Other Than Income Taxes 12.5 12.4 25.0 23.7
TOTAL EXPENSES 290.5 249.0 577.3 543.9
OPERATING INCOME 54.0 59.6 63.3 62.0
Other Income (Expense):
Interest Income 1.6 - 1.7 0.1
Allowance for Equity Funds Used During Construction 0.6 0.9 1.0 1.9
Non-Service Cost Components of Net Periodic Benefit Cost 2.2 2.1 4.3 4.2
Interest Expense (14.1) (15.5) (28.5) (31.3)
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 44.3 47.1 41.8 36.9
Income Tax Expense (Benefit) (1.8) 0.7 (1.6) 0.8
NET INCOME $ 46.1 $ 46.4 $ 43.4 $ 36.1
The common stock of PSO is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
119




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 46.1 $ 46.4 $ 43.4 $ 36.1
OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $0 and $(0.1) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0 and $(0.2) for the Six Months Ended June 30, 2021 and 2020, Respectively.
- (0.3) (0.1) (0.5)
TOTAL COMPREHENSIVE INCOME $ 46.1 $ 46.1 $ 43.3 $ 35.6
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
120




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2019 $ 157.2 $ 364.0 $ 851.0 $ 1.1 $ 1,373.3
ASU 2016-13 Adoption 0.3 0.3
Net Loss (10.3) (10.3)
Other Comprehensive Loss (0.2) (0.2)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2020 157.2 364.0 841.0 0.9 1,363.1
Net Income 46.4 46.4
Other Comprehensive Loss (0.3) (0.3)
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2020 $ 157.2 $ 364.0 $ 887.4 $ 0.6 $ 1,409.2
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020 $ 157.2 $ 414.0 $ 974.3 $ 0.1 $ 1,545.6
Capital Contribution from Parent 425.0 425.0
Net Loss (2.7) (2.7)
Other Comprehensive Loss (0.1) (0.1)
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 157.2 839.0 971.6 - 1,967.8
Capital Contribution from Parent 200.0 200.0
Common Stock Dividends (10.0) (10.0)
Net Income 46.1 46.1
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 $ 157.2 $ 1,039.0 $ 1,007.7 $ - $ 2,203.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
121




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents $ 2.6 $ 2.6
Accounts Receivable:
Customers 38.6 30.8
Affiliated Companies 31.9 15.6
Miscellaneous - 2.0
Total Accounts Receivable 70.5 48.4
Fuel 10.6 17.9
Materials and Supplies 52.8 54.0
Risk Management Assets 23.0 10.3
Accrued Tax Benefits 0.2 10.9
Regulatory Asset for Under-Recovered Fuel Costs 84.8 30.1
Prepayments and Other Current Assets 11.5 7.1
TOTAL CURRENT ASSETS 256.0 181.3
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 1,609.3 1,480.7
Transmission 1,088.1 1,069.9
Distribution 2,927.2 2,853.0
Other Property, Plant and Equipment 420.2 393.3
Construction Work in Progress 106.9 128.7
Total Property, Plant and Equipment 6,151.7 5,925.6
Accumulated Depreciation and Amortization 1,653.2 1,605.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 4,498.5 4,320.0
OTHER NONCURRENT ASSETS
Regulatory Assets 1,054.0 375.0
Employee Benefits and Pension Assets 66.1 65.8
Operating Lease Assets 54.1 42.6
Deferred Charges and Other Noncurrent Assets 29.7 6.0
TOTAL OTHER NONCURRENT ASSETS 1,203.9 489.4
TOTAL ASSETS $ 5,958.4 $ 4,990.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
122




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
June 30, December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 135.1 $ 155.4
Accounts Payable:
General 117.1 107.0
Affiliated Companies 41.6 43.4
Long-term Debt Due Within One Year - Nonaffiliated 0.5 0.5
Customer Deposits 54.1 54.8
Accrued Taxes 75.3 26.8
Obligations Under Operating Leases 6.7 6.5
Other Current Liabilities 61.8 84.2
TOTAL CURRENT LIABILITIES 492.2 478.6
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 1,623.3 1,373.3
Deferred Income Taxes 668.4 688.5
Regulatory Liabilities and Deferred Investment Tax Credits 852.6 802.2
Asset Retirement Obligations 49.7 45.7
Obligations Under Operating Leases 47.5 36.2
Deferred Credits and Other Noncurrent Liabilities 20.8 20.6
TOTAL NONCURRENT LIABILITIES 3,262.3 2,966.5
TOTAL LIABILITIES 3,754.5 3,445.1
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
COMMON SHAREHOLDER'S EQUITY
Common Stock - Par Value - $15 Per Share:
Authorized - 11,000,000 Shares
Issued - 10,482,000 Shares
Outstanding - 9,013,000 Shares
157.2 157.2
Paid-in Capital 1,039.0 414.0
Retained Earnings 1,007.7 974.3
Accumulated Other Comprehensive Income (Loss) - 0.1
TOTAL COMMON SHAREHOLDER'S EQUITY 2,203.9 1,545.6
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY $ 5,958.4 $ 4,990.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
123




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 43.4 $ 36.1
Adjustments to Reconcile Net Loss to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization 100.1 89.7
Deferred Income Taxes 25.7 (9.2)
Allowance for Equity Funds Used During Construction (1.0) (1.9)
Mark-to-Market of Risk Management Contracts (12.7) (7.9)
Property Taxes (21.8) (21.2)
Deferred Fuel Over/Under-Recovery, Net (724.1) (17.1)
Change in Other Noncurrent Assets (16.6) (4.8)
Change in Other Noncurrent Liabilities 0.4 1.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (22.1) (24.3)
Fuel, Materials and Supplies 8.5 (18.1)
Accounts Payable 11.7 (1.5)
Accrued Taxes, Net 59.2 38.5
Other Current Assets (4.4) 1.8
Other Current Liabilities (22.0) (10.0)
Net Cash Flows from (Used for) Operating Activities (575.7) 51.4
INVESTING ACTIVITIES
Construction Expenditures (145.9) (184.8)
Change in Advances to Affiliates, Net - 38.8
Acquisition of the North Central Wind Energy Facilities (122.8) -
Other Investing Activities 1.3 2.0
Net Cash Flows Used for Investing Activities (267.4) (144.0)
FINANCING ACTIVITIES
Capital Contributions from Parent 625.0 -
Issuance of Long-term Debt - Nonaffiliated 500.0 -
Change in Advances from Affiliates, Net (20.3) 106.9
Retirement of Long-term Debt - Nonaffiliated (250.3) (12.9)
Principal Payments for Finance Lease Obligations (1.7) (1.8)
Dividends Paid on Common Stock (10.0) -
Other Financing Activities 0.4 0.3
Net Cash Flows from Financing Activities 843.1 92.5
Net Decrease in Cash and Cash Equivalents - (0.1)
Cash and Cash Equivalents at Beginning of Period 2.6 1.5
Cash and Cash Equivalents at End of Period $ 2.6 $ 1.4
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 32.2 $ 30.6
Net Cash Paid (Received) for Income Taxes (65.0) (2.7)
Noncash Acquisitions Under Finance Leases 2.3 2.6
Construction Expenditures Included in Current Liabilities as of June 30, 27.9 25.3
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
124






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

125




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT'S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in millions of KWhs)
Retail:
Residential 1,274 1,346 2,974 2,752
Commercial 1,396 1,236 2,605 2,464
Industrial 1,294 1,187 2,265 2,429
Miscellaneous 21 20 39 40
Total Retail 3,985 3,789 7,883 7,685
Wholesale 1,392 1,184 2,933 2,510
Total KWhs 5,377 4,973 10,816 10,195

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.

Summary of Heating and Cooling Degree Days
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
(in degree days)
Actual - Heating (a) 26 25 789 522
Normal - Heating (b) 25 25 722 723
Actual - Cooling (c) 728 674 773 743
Normal - Cooling (b) 739 741 779 780

(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.

126




Second Quarter of 2021 Compared to Second Quarter of 2020
Reconciliation of Second Quarter of 2020 to Second Quarter of 2021
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Second Quarter of 2020 $ 58.8
Changes in Gross Margin:
Retail Margins (a) 5.9
Margins from Off-system Sales 1.0
Transmission Revenues (4.9)
Other Revenues 1.2
Total Change in Gross Margin 3.2
Changes in Expenses and Other:
Other Operation and Maintenance (17.7)
Depreciation and Amortization (4.9)
Taxes Other Than Income Taxes (5.1)
Interest Income 2.6
Allowance for Equity Funds Used During Construction 1.0
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (1.7)
Total Change in Expenses and Other (25.9)
Income Tax Expense 0.8
Equity Earnings of Unconsolidated Subsidiary 0.1
Net Income Attributable to Noncontrolling Interest (0.2)
Second Quarter of 2021 $ 36.8

(a)Includes firm wholesale sales to municipals and cooperatives.
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 Marginsincreased $6 million primarily due to the following:
A $3 million increase in weather-related usage primarily due to an 8% increase in cooling degree days.
A $3 million increase in municipal and cooperative revenues primarily due to the annual generation formula rate true-up.
Transmission Revenuesdecreased $5 million primarily due to the following:
An $8 million decrease due to the annual transmission formula rate true-up.
This decrease was partially offset by:
A $3 million increase due to an increase in transmission investment.
Expenses and Other and Income Tax Expense changed between years as follows:

Other Operation and Maintenanceexpenses increased $18 million primarily due to the following:
A $14 million increase in transmission related expenses primarily due to a $10 million increase as a result of the annual formula rate true-up.
A $6 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
A $4 million increase in regulatory and rate case related expenses.
These increases were partially offset by:
A $6 million decrease in overhead line maintenance primarily related to storm restoration.
Depreciation and Amortizationexpenses increased $5 million primarily due to a higher depreciable base.
127




Taxes Other Than Income Taxesincreased $5 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to the Stall Plant.
Income Tax Expensedecreased $1 million primarily due to a decrease in pretax book income partially offset by a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
128




Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020
Reconciliation of Six Months Ended June 30, 2020 to Six Months Ended June 30, 2021
Earnings Attributable to SWEPCo Common Shareholder
(in millions)
Six Months Ended June 30, 2020 $ 73.9
Changes in Gross Margin:
Retail Margins (a) 46.1
Margins from Off-system Sales 21.2
Transmission Revenues (2.7)
Other Revenues 1.2
Total Change in Gross Margin 65.8
Changes in Expenses and Other:
Other Operation and Maintenance (16.0)
Depreciation and Amortization (7.2)
Taxes Other Than Income Taxes (9.8)
Interest Income 3.0
Allowance for Equity Funds Used During Construction 1.7
Non-Service Cost Components of Net Periodic Benefit Cost (0.1)
Interest Expense (0.9)
Total Change in Expenses and Other (29.3)
Income Tax Expense (11.0)
Net Income Attributable to Noncontrolling Interest (0.2)
Six Months Ended June 30, 2021 $ 99.2

(a)Includes firm wholesale sales to municipals and cooperatives.

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 Marginsincreased $46 million primarily due to the following:
A $13 million increase in weather-related usage primarily due to a 51% increase in heating degree days.
A $10 million increase in weather-normalized wholesale margins.
An $8 million increase in recoverable fuel costs primarily due to timing of recovery.
A $5 million increase in municipal and cooperative revenues primarily due to the annual generation formula rate true-up.
A $5 million increase due to a decrease in the return of Excess ADIT benefits to customers. This increase was offset in Income Tax Expense below.
A $4 million increase in weather-normalized retail margins.
Margins from Off-system Salesincreased $21 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event.
Transmission Revenues decreased $3 million primarily due to the following:
An $8 million decrease due to the annual transmission formula rate true-up.
This decrease was partially offset by:
A $5 million increase due to an increase in transmission investment.
129




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

Other Operation and Maintenanceexpenses increased $16 million primarily due to the following:
A $15 million increase in transmission related expenses primarily due to a $10 million increase as a result of the annual formula rate true-up.
A $5 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.
Depreciation and Amortization expenses increased $7 million primarily due to a higher depreciable base.
Taxes Other Than Income Taxesincreased $10 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.
Interest Incomeincreased $3 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
Income Tax Expense increased $11 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
130





SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
REVENUES
Electric Generation, Transmission and Distribution $ 418.8 $ 401.0 $ 1,026.5 $ 778.6
Sales to AEP Affiliates 10.9 13.1 18.7 20.6
Other Revenues 0.4 0.9 1.0 1.7
TOTAL REVENUES 430.1 415.0 1,046.2 800.9
EXPENSES
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation 138.5 126.6 438.3 258.8
Other Operation 88.6 70.0 178.9 162.2
Maintenance 31.8 32.7 65.8 66.5
Depreciation and Amortization 73.0 68.1 142.6 135.4
Taxes Other Than Income Taxes 30.1 25.0 60.1 50.3
TOTAL EXPENSES 362.0 322.4 885.7 673.2
OPERATING INCOME 68.1 92.6 160.5 127.7
Other Income (Expense):
Interest Income 3.1 0.5 4.1 1.1
Allowance for Equity Funds Used During Construction 1.9 0.9 4.0 2.3
Non-Service Cost Components of Net Periodic Benefit Cost 2.0 2.1 4.1 4.2
Interest Expense (31.4) (29.7) (60.7) (59.8)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS 43.7 66.4 112.0 75.5
Income Tax Expense 7.1 7.9 12.7 1.7
Equity Earnings of Unconsolidated Subsidiary 0.8 0.7 1.5 1.5
NET INCOME 37.4 59.2 100.8 75.3
Net Income Attributable to Noncontrolling Interest 0.6 0.4 1.6 1.4
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$ 36.8 $ 58.8 $ 99.2 $ 73.9
The common stock of SWEPCo is wholly-owned by Parent.
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
131




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net Income $ 37.4 $ 59.2 $ 100.8 $ 75.3
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended June 30, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Six Months Ended June 30, 2021 and 2020, Respectively
0.4 0.3 0.8 0.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended June 30, 2021 and 2020, Respectively, and $(0.2) and $(0.2) for the Six Months Ended June 30, 2021 and 2020, Respectively
(0.4) (0.3) (0.8) (0.7)
TOTAL OTHER COMPREHENSIVE INCOME - - - -
TOTAL COMPREHENSIVE INCOME 37.4 59.2 100.8 75.3
Total Comprehensive Income Attributable to Noncontrolling Interest 0.6 0.4 1.6 1.4
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
$ 36.8 $ 58.8 $ 99.2 $ 73.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
132




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
SWEPCo Common Shareholder
Common
Stock
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
Total
TOTAL EQUITY - DECEMBER 31, 2019 $ 135.7 $ 676.6 $ 1,629.5 $ (1.3) $ 0.6 $ 2,441.1
Common Stock Dividends - Nonaffiliated (0.7) (0.7)
ASU 2016-13 Adoption 1.6 1.6
Net Income 15.1 1.0 16.1
TOTAL EQUITY - MARCH 31, 2020 135.7 676.6 1,646.2 (1.3) 0.9 2,458.1
Common Stock Dividends - Nonaffiliated (1.2) (1.2)
Net Income 58.8 0.4 59.2
TOTAL EQUITY - JUNE 30, 2020 $ 135.7 $ 676.6 $ 1,705.0 $ (1.3) $ 0.1 $ 2,516.1
TOTAL EQUITY - DECEMBER 31, 2020 $ 0.1 $ 812.2 $ 1,811.9 $ 1.9 $ 1.6 $ 2,627.7
Capital Contribution from Parent 100.0 100.0
Common Stock Dividends - Nonaffiliated (1.0) (1.0)
Net Income 62.4 1.0 63.4
TOTAL EQUITY - MARCH 31, 2021 0.1 912.2 1,874.3 1.9 1.6 2,790.1
Capital Contribution from Parent 75.0 75.0
Common Stock Dividends - Nonaffiliated (0.6) (0.6)
Net Income 36.8 0.6 37.4
TOTAL EQUITY - JUNE 30, 2021 $ 0.1 $ 987.2 $ 1,911.1 $ 1.9 $ 1.6 $ 2,901.9
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
133




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2021 and December 31, 2020
(in millions)
(Unaudited)
June 30, December 31,
2021 2020
CURRENT ASSETS
Cash and Cash Equivalents
(June 30, 2021 and December 31, 2020 Amounts Include $24.9 and $10.1, Respectively, Related to Sabine)
$ 28.0 $ 13.2
Advances to Affiliates 29.7 2.1
Accounts Receivable:
Customers 102.2 27.1
Affiliated Companies 30.1 25.1
Miscellaneous 14.6 12.7
Total Accounts Receivable 146.9 64.9
Fuel
(June 30, 2021 and December 31, 2020 Amounts Include $20.3 and $35.2, Respectively, Related to Sabine)
179.1 191.1
Materials and Supplies
(June 30, 2021 and December 31, 2020 Amounts Include $18.2 and $23.3, Respectively, Related to Sabine)
88.1 95.8
Risk Management Assets 14.0 3.2
Accrued Tax Benefits 14.5 29.9
Regulatory Asset for Under-Recovered Fuel Costs - 2.6
Prepayments and Other Current Assets 16.4 25.2
TOTAL CURRENT ASSETS 516.7 428.0
PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation 4,839.4 4,681.4
Transmission 2,260.0 2,165.7
Distribution 2,475.7 2,382.5
Other Property, Plant and Equipment
(June 30, 2021 and December 31, 2020 Amounts Include $219.9 and $223.7, Respectively, Related to Sabine)
809.0 788.8
Construction Work in Progress 159.8 228.3
Total Property, Plant and Equipment 10,543.9 10,246.7
Accumulated Depreciation and Amortization
(June 30, 2021 and December 31, 2020 Amounts Include $144.6 and $126.5, Respectively, Related to Sabine)
3,375.4 3,158.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET 7,168.5 7,088.2
OTHER NONCURRENT ASSETS
Regulatory Assets 1,006.2 403.1
Long-term Risk Management Assets 0.6 -
Deferred Charges and Other Noncurrent Assets 283.2 234.8
TOTAL OTHER NONCURRENT ASSETS 1,290.0 637.9
TOTAL ASSETS $ 8,975.2 $ 8,154.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
134




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2021 and December 31, 2020
(Unaudited)
June 30, December 31,
2021 2020
(in millions)
CURRENT LIABILITIES
Advances from Affiliates $ 149.6 $ 124.6
Accounts Payable:
General 121.8 135.9
Affiliated Companies 50.1 43.0
Short-term Debt - Nonaffiliated - 35.0
Long-term Debt Due Within One Year - Nonaffiliated 381.2 106.2
Risk Management Liabilities - 0.7
Customer Deposits 60.7 61.3
Accrued Taxes 108.3 41.0
Accrued Interest 36.0 34.6
Obligations Under Operating Leases 8.3 7.9
Other Current Liabilities 130.5 173.4
TOTAL CURRENT LIABILITIES 1,046.5 763.6
NONCURRENT LIABILITIES
Long-term Debt - Nonaffiliated 2,749.5 2,530.2
Long-term Risk Management Liabilities - 1.0
Deferred Income Taxes 1,040.3 1,017.6
Regulatory Liabilities and Deferred Investment Tax Credits 874.8 863.4
Asset Retirement Obligations 191.6 193.7
Employee Benefits and Pension Obligations 22.9 18.6
Obligations Under Operating Leases 58.5 44.1
Deferred Credits and Other Noncurrent Liabilities 89.2 94.2
TOTAL NONCURRENT LIABILITIES 5,026.8 4,762.8
TOTAL LIABILITIES 6,073.3 5,526.4
Rate Matters (Note 4)
Commitments and Contingencies (Note 5)
EQUITY
Common Stock - Par Value - $18 Per Share:
Authorized - 3,680 Shares
Outstanding - 3,680 Shares
0.1 0.1
Paid-in Capital 987.2 812.2
Retained Earnings 1,911.1 1,811.9
Accumulated Other Comprehensive Income (Loss) 1.9 1.9
TOTAL COMMON SHAREHOLDER'S EQUITY 2,900.3 2,626.1
Noncontrolling Interest 1.6 1.6
TOTAL EQUITY 2,901.9 2,627.7
TOTAL LIABILITIES AND EQUITY $ 8,975.2 $ 8,154.1
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
135




SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2021 and 2020
(in millions)
(Unaudited)
Six Months Ended June 30,
2021 2020
OPERATING ACTIVITIES
Net Income $ 100.8 $ 75.3
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization 142.6 135.4
Deferred Income Taxes 8.1 (12.4)
Allowance for Equity Funds Used During Construction (4.0) (2.3)
Mark-to-Market of Risk Management Contracts (13.1) (1.8)
Property Taxes (41.7) (33.0)
Deferred Fuel Over/Under-Recovery, Net (470.6) 31.1
Change in Regulatory Assets (50.6) (4.3)
Change in Other Noncurrent Assets 17.3 2.7
Change in Other Noncurrent Liabilities 34.1 13.5
Changes in Certain Components of Working Capital:
Accounts Receivable, Net (82.0) (5.8)
Fuel, Materials and Supplies 29.1 (60.4)
Accounts Payable (5.2) 2.9
Accrued Taxes, Net 82.7 52.0
Other Current Assets 9.8 0.2
Other Current Liabilities (37.9) (32.6)
Net Cash Flows from (Used for) Operating Activities (280.6) 160.5
INVESTING ACTIVITIES
Construction Expenditures (182.5) (228.5)
Change in Advances to Affiliates, Net (27.6) -
Acquisition of the North Central Wind Energy Facilities (147.1) -
Other Investing Activities 1.0 4.3
Net Cash Flows Used for Investing Activities (356.2) (224.2)
FINANCING ACTIVITIES
Capital Contribution from Parent 175.0 -
Issuance of Long-term Debt - Nonaffiliated 496.4 -
Change in Short-term Debt - Nonaffiliated (35.0) 18.7
Change in Advances from Affiliates, Net 25.0 70.5
Retirement of Long-term Debt - Nonaffiliated (3.1) (18.1)
Principal Payments for Finance Lease Obligations (5.4) (5.5)
Dividends Paid on Common Stock - Nonaffiliated (1.6) (1.9)
Other Financing Activities 0.3 0.2
Net Cash Flows from Financing Activities 651.6 63.9
Net Increase in Cash and Cash Equivalents 14.8 0.2
Cash and Cash Equivalents at Beginning of Period 13.2 1.6
Cash and Cash Equivalents at End of Period $ 28.0 $ 1.8
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts $ 55.6 $ 57.0
Net Cash Paid (Received) for Income Taxes (12.8) 8.1
Noncash Acquisitions Under Finance Leases 3.2 4.3
Construction Expenditures Included in Current Liabilities as of June 30, 41.9 33.7
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 137.
136




INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANTS

The condensed notes to condensed 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
Significant Accounting Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
138
New Accounting Standards AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
140
Comprehensive Income AEP, AEP Texas, APCo, I&M, PSO, SWEPCo
141
Rate Matters AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
152
Commitments, Guarantees and Contingencies
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
167
Acquisitions and Dispositions AEP, PSO, SWEPCo
173
Benefit Plans AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
175
Business Segments AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
179
Derivatives and Hedging AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo
184
Fair Value Measurements AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
198
Income Taxes AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
215
Financing Activities AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
218
Property, Plant and Equipment AEP, APCo
226
Revenue from Contracts with Customers
AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo
227
137




1. SIGNIFICANT ACCOUNTING MATTERS

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

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair statement of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and six months ended June 30, 2021 is not necessarily indicative of results that may be expected for the year ending December 31, 2021. The condensed financial statements are unaudited and should be read in conjunction with the audited 2020 financial statements and notes thereto, which are included in the Registrants' Annual Reports on Form 10-K as filed with the SEC on February 25, 2021.

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:
Three Months Ended June 30,
2021 2020
(in millions, except per share data)
$/share $/share
Earnings Attributable to AEP Common Shareholders
$ 578.2 $ 520.8
Weighted-Average Number of Basic AEP Common Shares Outstanding 499.9 $ 1.16 495.7 $ 1.05
Weighted-Average Dilutive Effect of Stock-Based Awards 1.1 (0.01) 1.6 -
Weighted-Average Number of Diluted AEP Common Shares Outstanding 501.0 $ 1.15 497.3 $ 1.05
Six Months Ended June 30,
2021 2020
(in millions, except per share data)
$/share $/share
Earnings Attributable to AEP Common Shareholders
$ 1,153.2 $ 1,016.0
Weighted-Average Number of Basic AEP Common Shares Outstanding 498.5 $ 2.31 495.1 $ 2.05
Weighted-Average Dilutive Effect of Stock-Based Awards 1.1 - 1.9 (0.01)
Weighted-Average Number of Diluted AEP Common Shares Outstanding 499.6 $ 2.31 497.0 $ 2.04

Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and six months ended June 30, 2021 and 2020, as the dilutive stock price thresholds were not met. See Note 12 - Financing Activities for more information related to Equity Units.

138




There were 0 and 156 thousand antidilutive shares outstanding as of June 30, 2021 and 2020, respectively. The
antidilutive shares were excluded from the calculation of diluted EPS.

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 statements of cash flows:
June 30, 2021
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents
$ 312.7 $ 0.1 $ 3.9
Restricted Cash
47.0 27.9 19.1
Total Cash, Cash Equivalents and Restricted Cash
$ 359.7 $ 28.0 $ 23.0

December 31, 2020
AEP AEP Texas APCo
(in millions)
Cash and Cash Equivalents
$ 392.7 $ 0.1 $ 5.8
Restricted Cash
45.6 28.7 16.9
Total Cash, Cash Equivalents and Restricted Cash
$ 438.3 $ 28.8 $ 22.7


139




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.

140




3. COMPREHENSIVE INCOME

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

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.

AEP
Cash Flow Hedges Pension
Three Months Ended June 30, 2021 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2021 $ (18.5) $ (33.3) $ 21.0 $ (30.8)
Change in Fair Value Recognized in AOCI 136.4 (0.4) (a) - 136.0
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b) (0.1) - - (0.1)
Purchased Electricity for Resale (b)
(9.5) - - (9.5)
Interest Expense (b)
- 1.8 - 1.8
Amortization of Prior Service Cost (Credit) - - (4.9) (4.9)
Amortization of Actuarial (Gains) Losses - - 2.2 2.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(9.6) 1.8 (2.7) (10.5)
Income Tax (Expense) Benefit (2.0) 0.3 (0.6) (2.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(7.6) 1.5 (2.1) (8.2)
Net Current Period Other Comprehensive Income (Loss)
128.8 1.1 (2.1) 127.8
Balance in AOCI as of June 30, 2021 $ 110.3 $ (32.2) $ 18.9 $ 97.0
Cash Flow Hedges Pension
Three Months Ended June 30, 2020 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2020 $ (128.5) $ (53.5) $ (34.5) $ (216.5)
Change in Fair Value Recognized in AOCI 6.5 (2.8) (a) - 3.7
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b) (0.1) - - (0.1)
Purchased Electricity for Resale (b)
51.3 - - 51.3
Interest Expense (b)
- 1.4 - 1.4
Amortization of Prior Service Cost (Credit)
- - (4.6) (4.6)
Amortization of Actuarial (Gains) Losses
- - 2.5 2.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit
51.2 1.4 (2.1) 50.5
Income Tax (Expense) Benefit 10.6 0.4 (0.4) 10.6
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
40.6 1.0 (1.7) 39.9
Net Current Period Other Comprehensive Income (Loss)
47.1 (1.8) (1.7) 43.6
Balance in AOCI as of June 30, 2020 $ (81.4) $ (55.3) $ (36.2) $ (172.9)



141




AEP
Cash Flow Hedges Pension
Six Months Ended June 30, 2021 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (60.6) $ (47.5) $ 23.0 $ (85.1)
Change in Fair Value Recognized in AOCI 313.7 12.7 (a) - 326.4
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b) 0.7 - - 0.7
Purchased Electricity for Resale (b)
(181.5) - - (181.5)
Interest Expense (b)
- 3.3 - 3.3
Amortization of Prior Service Cost (Credit) - - (9.7) (9.7)
Amortization of Actuarial (Gains) Losses - - 4.5 4.5
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(180.8) 3.3 (5.2) (182.7)
Income Tax (Expense) Benefit (38.0) 0.7 (1.1) (38.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(142.8) 2.6 (4.1) (144.3)
Net Current Period Other Comprehensive Income (Loss)
170.9 15.3 (4.1) 182.1
Balance in AOCI as of June 30, 2021 $ 110.3 $ (32.2) $ 18.9 $ 97.0
Cash Flow Hedges Pension
Six Months Ended June 30, 2020 Commodity Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (103.5) $ (11.5) $ (32.7) $ (147.7)
Change in Fair Value Recognized in AOCI (58.8) (45.5) (a) - (104.3)
Amount of (Gain) Loss Reclassified from AOCI
Generation & Marketing Revenues (b) (0.2) - - (0.2)
Purchased Electricity for Resale (b)
102.4 - - 102.4
Interest Expense (b)
- 2.3 - 2.3
Amortization of Prior Service Cost (Credit)
- - (9.5) (9.5)
Amortization of Actuarial (Gains) Losses
- - 5.1 5.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
102.2 2.3 (4.4) 100.1
Income Tax (Expense) Benefit 21.3 0.6 (0.9) 21.0
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
80.9 1.7 (3.5) 79.1
Net Current Period Other Comprehensive Income (Loss)
22.1 (43.8) (3.5) (25.2)
Balance in AOCI as of June 30, 2020 $ (81.4) $ (55.3) $ (36.2) $ (172.9)

142




AEP Texas
Cash Flow Hedge - Pension
Three Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2021 $ (2.0) $ (6.6) $ (8.6)
Change in Fair Value Recognized in AOCI
(0.1) - (0.1)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.3 - 0.3
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.3 0.1 0.4
Income Tax (Expense) Benefit - - -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.3 0.1 0.4
Net Current Period Other Comprehensive Income (Loss) 0.2 0.1 0.3
Balance in AOCI as of June 30, 2021 $ (1.8) $ (6.5) $ (8.3)
Cash Flow Hedge - Pension
Three Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2020 $ (3.1) $ (9.4) $ (12.5)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.2 - 0.2
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.2 0.1 0.3
Income Tax (Expense) Benefit - - -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.2 0.1 0.3
Net Current Period Other Comprehensive Income (Loss) 0.2 0.1 0.3
Balance in AOCI as of June 30, 2020 $ (2.9) $ (9.3) $ (12.2)

143




AEP Texas
Cash Flow Hedge - Pension
Six Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (2.3) $ (6.6) $ (8.9)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.6 - 0.6
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.6 0.1 0.7
Income Tax (Expense) Benefit 0.1 - 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.5 0.1 0.6
Net Current Period Other Comprehensive Income (Loss) 0.5 0.1 0.6
Balance in AOCI as of June 30, 2021 $ (1.8) $ (6.5) $ (8.3)
Cash Flow Hedge - Pension
Six Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (3.4) $ (9.4) $ (12.8)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.6 - 0.6
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.6 0.1 0.7
Income Tax (Expense) Benefit 0.1 - 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.5 0.1 0.6
Net Current Period Other Comprehensive Income (Loss) 0.5 0.1 0.6
Balance in AOCI as of June 30, 2020 $ (2.9) $ (9.3) $ (12.2)


144




APCo
Cash Flow Hedge - Pension
Three Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2021 $ 8.2 $ 6.9 $ 15.1
Change in Fair Value Recognized in AOCI
(0.2) - (0.2)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) - - -
Amortization of Prior Service Cost (Credit) - (1.3) (1.3)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
- (1.3) (1.3)
Income Tax (Expense) Benefit - (0.3) (0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
- (1.0) (1.0)
Net Current Period Other Comprehensive Income (Loss)
(0.2) (1.0) (1.2)
Balance in AOCI as of June 30, 2021 $ 8.0 $ 5.9 $ 13.9
Cash Flow Hedge - Pension
Three Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2020 $ (3.3) $ 3.2 $ (0.1)
Change in Fair Value Recognized in AOCI
(0.6) - (0.6)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.2) - (0.2)
Amortization of Prior Service Cost (Credit) - (1.4) (1.4)
Amortization of Actuarial (Gains) Losses - 0.2 0.2
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.2) (1.2) (1.4)
Income Tax (Expense) Benefit - (0.2) (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.2) (1.0) (1.2)
Net Current Period Other Comprehensive Income (Loss)
(0.8) (1.0) (1.8)
Balance in AOCI as of June 30, 2020 $ (4.1) $ 2.2 $ (1.9)
145





APCo
Cash Flow Hedge - Pension
Six Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (0.8) $ 8.0 $ 7.2
Change in Fair Value Recognized in AOCI
9.1 - 9.1
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.4) - (0.4)
Amortization of Prior Service Cost (Credit) - (2.7) (2.7)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.4) (2.7) (3.1)
Income Tax (Expense) Benefit (0.1) (0.6) (0.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.3) (2.1) (2.4)
Net Current Period Other Comprehensive Income (Loss)
8.8 (2.1) 6.7
Balance in AOCI as of June 30, 2021 $ 8.0 $ 5.9 $ 13.9
Cash Flow Hedge - Pension
Six Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ 0.9 $ 4.1 $ 5.0
Change in Fair Value Recognized in AOCI
(4.5) - (4.5)
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.6) - (0.6)
Amortization of Prior Service Cost (Credit) - (2.7) (2.7)
Amortization of Actuarial (Gains) Losses - 0.3 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.6) (2.4) (3.0)
Income Tax (Expense) Benefit (0.1) (0.5) (0.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.5) (1.9) (2.4)
Net Current Period Other Comprehensive Income (Loss)
(5.0) (1.9) (6.9)
Balance in AOCI as of June 30, 2020 $ (4.1) $ 2.2 $ (1.9)

146




I&M
Cash Flow Hedge - Pension
Three Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2021 $ (7.8) $ 1.3 $ (6.5)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5 - 0.5
Amortization of Prior Service Cost (Credit) - (0.2) (0.2)
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.5 (0.1) 0.4
Income Tax (Expense) Benefit 0.1 - 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.4 (0.1) 0.3
Net Current Period Other Comprehensive Income (Loss)
0.4 (0.1) 0.3
Balance in AOCI as of June 30, 2021 $ (7.4) $ 1.2 $ (6.2)
Cash Flow Hedge - Pension
Three Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2020 $ (9.5) $ (1.7) $ (11.2)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5 - 0.5
Amortization of Prior Service Cost (Credit) - (0.1) (0.1)
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.5 - 0.5
Income Tax (Expense) Benefit 0.1 - 0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.4 - 0.4
Net Current Period Other Comprehensive Income (Loss)
0.4 - 0.4
Balance in AOCI as of June 30, 2020 $ (9.1) $ (1.7) $ (10.8)
147





I&M
Cash Flow Hedge - Pension
Six Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (8.3) $ 1.3 $ (7.0)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 1.1 - 1.1
Amortization of Prior Service Cost (Credit) - (0.4) (0.4)
Amortization of Actuarial (Gains) Losses - 0.3 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.1 (0.1) 1.0
Income Tax (Expense) Benefit 0.2 - 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.9 (0.1) 0.8
Net Current Period Other Comprehensive Income (Loss)
0.9 (0.1) 0.8
Balance in AOCI as of June 30, 2021 $ (7.4) $ 1.2 $ (6.2)
Cash Flow Hedge - Pension
Six Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (9.9) $ (1.7) $ (11.6)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 1.0 - 1.0
Amortization of Prior Service Cost (Credit) - (0.3) (0.3)
Amortization of Actuarial (Gains) Losses - 0.3 0.3
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.0 - 1.0
Income Tax (Expense) Benefit 0.2 - 0.2
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.8 - 0.8
Net Current Period Other Comprehensive Income (Loss)
0.8 - 0.8
Balance in AOCI as of June 30, 2020 $ (9.1) $ (1.7) $ (10.8)

148




PSO
Cash Flow Hedge -
Three Months Ended June 30, 2021 Interest Rate
(in millions)
Balance in AOCI as of March 31, 2021 $ -
Change in Fair Value Recognized in AOCI -
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) -
Balance in AOCI as of June 30, 2021 $ -
Cash Flow Hedge -
Three Months Ended June 30, 2020 Interest Rate
(in millions)
Balance in AOCI as of March 31, 2020 $ 0.9
Change in Fair Value Recognized in AOCI -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.4)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.4)
Income Tax (Expense) Benefit (0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.3)
Net Current Period Other Comprehensive Income (Loss) (0.3)
Balance in AOCI as of June 30, 2020 $ 0.6
Cash Flow Hedge -
Six Months Ended June 30, 2021 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2020 $ 0.1
Change in Fair Value Recognized in AOCI -
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 June 30, 2021 $ -
Cash Flow Hedge -
Six Months Ended June 30, 2020 Interest Rate
(in millions)
Balance in AOCI as of December 31, 2019 $ 1.1
Change in Fair Value Recognized in AOCI -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) (0.7)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
(0.7)
Income Tax (Expense) Benefit (0.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
(0.5)
Net Current Period Other Comprehensive Income (Loss) (0.5)
Balance in AOCI as of June 30, 2020 $ 0.6
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SWEPCo
Cash Flow Hedge - Pension
Three Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2021 $ 0.1 $ 1.8 $ 1.9
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.5 - 0.5
Amortization of Prior Service Cost (Credit) - (0.5) (0.5)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.5 (0.5) -
Income Tax (Expense) Benefit 0.1 (0.1) -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.4 (0.4) -
Net Current Period Other Comprehensive Income (Loss)
0.4 (0.4) -
Balance in AOCI as of June 30, 2021 $ 0.5 $ 1.4 $ 1.9
Cash Flow Hedge - Pension
Three Months Ended June 30, 2020 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of March 31, 2020 $ (1.4) $ 0.1 $ (1.3)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.4 - 0.4
Amortization of Prior Service Cost (Credit) - (0.5) (0.5)
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.4 (0.4) -
Income Tax (Expense) Benefit 0.1 (0.1) -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.3 (0.3) -
Net Current Period Other Comprehensive Income (Loss)
0.3 (0.3) -
Balance in AOCI as of June 30, 2020 $ (1.1) $ (0.2) $ (1.3)
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SWEPCo
Cash Flow Hedge - Pension
Six Months Ended June 30, 2021 Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2020 $ (0.3) $ 2.2 $ 1.9
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 1.0 - 1.0
Amortization of Prior Service Cost (Credit) - (1.0) (1.0)
Reclassifications from AOCI, before Income Tax (Expense) Benefit
1.0 (1.0) -
Income Tax (Expense) Benefit 0.2 (0.2) -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.8 (0.8) -
Net Current Period Other Comprehensive Income (Loss)
0.8 (0.8) -
Balance in AOCI as of June 30, 2021 $ 0.5 $ 1.4 $ 1.9
Cash Flow Hedge - Pension
Six Months Ended June 30, 2020
Interest Rate and OPEB Total
(in millions)
Balance in AOCI as of December 31, 2019 $ (1.8) $ 0.5 $ (1.3)
Change in Fair Value Recognized in AOCI
- - -
Amount of (Gain) Loss Reclassified from AOCI
Interest Expense (b) 0.9 - 0.9
Amortization of Prior Service Cost (Credit) - (1.0) (1.0)
Amortization of Actuarial (Gains) Losses - 0.1 0.1
Reclassifications from AOCI, before Income Tax (Expense) Benefit
0.9 (0.9) -
Income Tax (Expense) Benefit 0.2 (0.2) -
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit
0.7 (0.7) -
Net Current Period Other Comprehensive Income (Loss)
0.7 (0.7) -
Balance in AOCI as of June 30, 2020 $ (1.1) $ (0.2) $ (1.3)
(a)The change in fair value includes $4 million and $2 million, respectively, for the three months ended June 30, 2021 and 2020 and $0 million and $7 million, respectively, for the six months ended June 30, 2021 and 2020 related to AEP's investment in joint venture wind farms acquired as part of the purchase of Sempra Renewables LLC.
(b)Amounts reclassified to the referenced line item on the statements of income.

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4. RATE MATTERS

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

As discussed in the 2020 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2020 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2021 and updates the 2020 Annual Report.

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 are not deemed recoverable, it could materially reduce future net income and cash flows and impact financial condition.

Regulated Generating Units that have been Retired

PSO

In September 2020, the Oklaunion Power Station was retired. As of June 30, 2021, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet of $34 million. PSO is seeking accelerated recovery of the Oklaunion Power Station through 2026 in its 2021 Oklahoma base rate case. See '2021 Oklahoma Base Rate Case' section below for additional information. In October 2020, the Oklaunion Power Station site was sold to a nonaffiliated third-party.

SWEPCo

In April 2016, Welsh Plant, Unit 2 was retired. As part of the 2016 Texas Base Rate Case, SWEPCo received approval from the PUCT to recover the Texas jurisdictional share of Welsh Plant, Unit 2. See '2016 Texas Base Rate Case' section below 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. As of June 30, 2021, SWEPCo has a regulatory asset for plant retirement costs pending approval recorded on its balance sheet of $35 million related to the Louisiana jurisdictional share of Welsh Plant, Unit 2. See '2020 Louisiana Base Rate Case' section below 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 its 2021 Oklahoma base rate case, PSO is seeking to accelerate the recovery of Northeastern Plant, Unit 3 from the original retirement date of 2040 to the projected retirement date of 2026. See '2021 Oklahoma Base Rate Case' section below for additional information.
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SWEPCo

In January 2020, as part of the 2019 Arkansas Base Rate Case, management announced that the Dolet Hills Power Station was probable of abandonment and was to be retired by December 2026. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation. In March 2020, management announced plans to retire the plant in 2021.

In November 2020, management announced plans to retire Pirkey Power Plant in 2023 and that it will cease using coal at the Welsh Plant in 2028. As a result of the announcement, SWEPCo began recording a regulatory asset for accelerated depreciation.

The table below summarizes the net book value including CWIP, before cost of removal and materials and supplies, as of June 30, 2021, of generating facilities planned for early retirement:
Plant Net
Investment
Accelerated Depreciation Regulatory Asset Cost of Removal
Regulatory Liability
Projected
Retirement Date
Current Authorized
Recovery Period
Annual
Depreciation (a)
(dollars in millions)
Northeastern Plant, Unit 3 $ 183.2 $ 119.2 $ 19.9 (b) 2026 (c) $ 14.9
Dolet Hills Power Station
27.3 114.3 24.2 2021 (d) 7.8
Pirkey Power Plant 157.1 49.4 38.9 2023 (e) 13.6
Welsh Plant, Units 1 and 3 511.2 24.9 57.8 (f) 2028 (g) 33.2
(a)Represents the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(b)Includes Northeastern Plant, Unit 4, which was retired in 2016. Removal of Northeastern Plant, Unit 4, will be performed with Northeastern Plant, Unit 3, after retirement.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040. Accelerated recovery has been requested in the 2021 Oklahoma base rate case.
(d)Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction and through 2046 in the Arkansas and Texas jurisdictions.
(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(f)Includes Welsh Plant, Unit 2, which was retired in 2016. Removal of Welsh Plant, Unit 2, will be performed with Welsh Plant, Units 1 and 3, after retirement.
(g)Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.

Dolet Hills Power Station and Related Fuel Operations (Applies to AEP and SWEPCo)

DHLC provides 100% of the fuel supply to Dolet Hills Power Station. During the second quarter of 2019, the Dolet Hills Power Station initiated a seasonal operating schedule. In 2020, management of SWEPCo and CLECO determined DHLC would not proceed developing additional Oxbow Lignite Company (Oxbow) mining areas for future lignite extraction and ceased extraction of lignite at the mine in May 2020. Based on these actions, management revised the estimated useful life of DHLC's and Oxbow's assets to coincide with the date at which extraction was discontinued in the second quarter of 2020 and the date at which delivery of lignite is expected to cease in September 2021. In addition, management also revised the useful life of the Dolet Hills Power Station to 2021 based on the remaining estimated fuel supply available for continued seasonal operation. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining.

The Dolet Hills Power Station non-fuel costs are recoverable by SWEPCo through base rates. SWEPCo's share of the net investment in the Dolet Hills Power Station is $147 million, including CWIP and materials and supplies, before cost of removal.

Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Under the fuel agreements, SWEPCo's fuel inventory and unbilled fuel costs from mining related activities were $119 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Dolet Hills Power Station. Additional operational, reclamation and other land-related costs incurred by DHLC and Oxbow will be billed to SWEPCo and included in future fuel clauses.
153




In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas, including Dolet Hills, for the reconciliation period of March 1, 2017 to December 31, 2019. See '2020 Texas Fuel Reconciliation' section below for additional information.

In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date.

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

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

Pirkey Power Plant and Related Fuel Operations (Applies to AEP and SWEPCo)

In 2020, management announced plans to retire the Pirkey Power Plant in 2023. The Pirkey Power Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses. SWEPCo's share of the net investment in the Pirkey Power Plant is $206 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Power Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an 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 $148 million as of June 30, 2021. Also, as of June 30, 2021, SWEPCo had a net over-recovered fuel balance of $17 million, excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed at the Pirkey Power Plant. Additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in future fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2020 Texas Fuel Reconciliation (Applies to AEP and SWEPCo)

In June 2020, SWEPCo filed a fuel reconciliation with the PUCT for its retail operations in Texas for the reconciliation period of March 1, 2017 to December 31, 2019. The fuel reconciliation included total fuel costs of $1.7 billion ($616 million of which is related to the Texas jurisdiction). In January 2021, various parties filed testimony recommending fuel cost disallowances totaling $125 million relating to the Texas jurisdiction. Also in January 2021, SWEPCo filed rebuttal testimony disputing the recommended disallowances. In February 2021, SWEPCo and various parties reached a settlement in principle which resulted in a $10 million reduction in recoverable fuel costs for the reconciliation period, which was recognized in SWEPCo's 2020 financial statements. In June 2021, the settlement was filed and approved by the PUCT. If additional costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
AEP
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a) $ 1,122.4 $ -
Dolet Hills Power Station Accelerated Depreciation 114.3 71.2
Pirkey Power Plant Accelerated Depreciation 49.4 12.2
Kentucky Deferred Purchase Power Expenses 44.4 41.3
Plant Retirement Costs - Unrecovered Plant, Louisiana 35.2 35.2
Oklaunion Power Station Accelerated Depreciation 33.5 34.4
Welsh Plant, Units 1 and 3 Accelerated Depreciation 24.9 3.6
Other Regulatory Assets Pending Final Regulatory Approval 26.8 22.8
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 301.0 134.2
Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9
COVID-19 17.4 24.9
Environmental Expense Deferral - Virginia 13.6 9.3
Other Regulatory Assets Pending Final Regulatory Approval 37.2 27.2
Total Regulatory Assets Pending Final Regulatory Approval $ 1,846.0 $ 442.2

(a)PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See 'Impacts of Severe Winter Weather' section below for additional information.

AEP Texas
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Advanced Metering System $ 16.6 $ 16.3
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 13.7 0.8
COVID-19 6.5 10.5
Vegetation Management Program 5.2 3.8
Texas Retail Electric Provider Bad Debt Expense 4.1 -
Other Regulatory Assets Pending Final Regulatory Approval 4.3 1.5
Total Regulatory Assets Pending Final Regulatory Approval $ 50.4 $ 32.9

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APCo
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
COVID-19 - Virginia $ 4.8 $ 3.7
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 55.2 3.4
Plant Retirement Costs - Asset Retirement Obligation Costs 25.9 25.9
Environmental Expense Deferral - Virginia 13.6 9.3
COVID-19 - West Virginia 1.9 1.5
Other Regulatory Assets Pending Final Regulatory Approval 0.1 -
Total Regulatory Assets Pending Final Regulatory Approval $ 101.5 $ 43.8

I&M
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Other Regulatory Assets Pending Final Regulatory Approval $ - $ 0.5
Regulatory Assets Currently Not Earning a Return
COVID-19 1.6 3.8
Other Regulatory Assets Pending Final Regulatory Approval 0.6 -
Total Regulatory Assets Pending Final Regulatory Approval $ 2.2 $ 4.3

OPCo
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs $ 6.7 $ 4.0
COVID-19 1.8 4.4
Other Regulatory Assets Pending Final Regulatory Approval 0.1 -
Total Regulatory Assets Pending Final Regulatory Approval $ 8.6 $ 8.4

PSO
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a) $ 669.4 $ -
Oklaunion Power Station Accelerated Depreciation 33.5 34.4
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 28.0 15.8
Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.3
Total Regulatory Assets Pending Final Regulatory Approval $ 731.7 $ 50.5

(a)PSO has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See 'Impacts of Severe Winter Weather' section below for additional information.

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SWEPCo
June 30, December 31,
2021 2020
Noncurrent Regulatory Assets (in millions)
Regulatory Assets Currently Earning a Return
Unrecovered Winter Storm Fuel Costs (a) $ 453.0 $ -
Dolet Hills Power Station Accelerated Depreciation 114.3 71.2
Pirkey Power Plant Accelerated Depreciation 49.4 12.2
Plant Retirement Costs -Unrecovered Plant, Louisiana
35.2 35.2
Welsh Plant, Units 1 and 3 Accelerated Depreciation 24.9 3.6
Other Regulatory Assets Pending Final Regulatory Approval 5.4 2.2
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs 144.3 99.3
Asset Retirement Obligation - Louisiana 9.7 9.1
Other Regulatory Assets Pending Final Regulatory Approval 16.4 14.5
Total Regulatory Assets Pending Final Regulatory Approval $ 852.6 $ 247.3

(a)SWEPCo has an active fuel clause that allows for the recovery of prudently incurred fuel and purchased power expenses. However, the recovery of these costs from customers may be extended over longer than usual time periods to mitigate the impact on customer bills. See 'Impacts of Severe Winter Weather' section below for additional information.

If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

Impacts of Severe Winter Weather

Storm Restoration Costs (Applies to AEP, APCo and SWEPCo)

In February 2021, severe winter weather impacted the service territories of APCo, KPCo and SWEPCo resulting in power outages and extensive damage to transmission and distribution infrastructures. As a result, incremental restoration expenses have been deferred related to the severe winter weather. The current estimate of storm restoration costs are as follows:

June 30, 2021
Company Jurisdiction Capital O&M Regulatory Asset Total
(in millions)
APCo Virginia $ 8.0 $ 2.2 $ 6.6 $ 16.8
APCo West Virginia 22.3 - 42.7 65.0
SWEPCo Louisiana 5.7 - 45.7 51.4
KPCo Kentucky 28.6 4.2 42.6 75.4
Total $ 64.6 $ 6.4 $ 137.6 $ 208.6

The amounts in the table above represent estimates as of June 30, 2021, and are subject to true-up as additional information becomes available. In March 2021, the LPSC approved the deferral of incremental other operation and maintenance storm restoration expenses related to the Louisiana jurisdiction for SWEPCo. Similarly, in April 2021, the KPSC approved deferral of KPCo's incremental other operation and maintenance storm restoration expenses. KPCo intends to seek recovery of these incremental storm restoration costs in their next base rate case while APCo and SWEPCo are expected to seek recovery in separate filings. If any of the restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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February 2021 Severe Winter Weather Impacts in SPP (Applies to AEP, PSO and SWEPCo)

The February 2021 severe winter weather also 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. From February 9, 2021, to February 20, 2021, PSO's and SWEPCo's natural gas expenses and purchases of electricity still to be recovered from customers are as follows:
PSO SWEPCo Total
(in millions)
Retail Customers (a) $ 669.4 $ 453.0 (b) $ 1,122.4
Wholesale Customers - 62.8 62.8
Total $ 669.4 $ 515.8 $ 1,185.2

(a)These costs were deferred as regulatory assets as of June 30, 2021.
(b)SWEPCo's balance consists of $116 million, $161 million and $176 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.

Retail Customers

PSO and SWEPCo have active fuel clauses that allow for the recovery of prudently incurred fuel and purchased power expenses. Given the significance of these costs, PSO and SWEPCo expect the costs to be subject to prudency reviews. Management believes these costs are probable of future recovery, but expects the recovery period to be extended to mitigate the impact on customer bills.

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. Accordingly, in April 2021, SWEPCo began recovery of its Arkansas jurisdictional share of these fuel costs, which are subject to true-up by the APSC. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a pretax rate of return of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a pretax rate of return of 1.65%. In July 2021, the APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. Once testimony concludes, a hearing will be scheduled. The prudency of these fuel costs is expected to be addressed in a separate proceeding.

In March 2021, the LPSC approved a special order granting a temporary modification to the FAC that allows SWEPCo to recover the Louisiana jurisdictional share of these retail fuel costs over a longer period than what the FAC traditionally allows. In April 2021, SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five year recovery period. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.

In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including carrying costs 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 to securitize the extraordinary fuel and purchase of electricity costs impacting the utilities within the state. Under the legislation, the OCC has the authority to determine, after receiving an application from a rate-regulated utility, if the extraordinary fuel and purchase of electricity costs incurred in February 2021 may be mitigated through securitization to reduce the impact on customer bills. PSO has filed an application for a financing order to pursue securitization.

SWEPCo expects to make a filing with the PUCT in the third quarter of 2021 to seek a recovery mechanism and an appropriate carrying charge for the Texas jurisdictional share of the retail fuel costs.

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Wholesale Customers

During the first quarter of 2021, SWEPCo billed wholesale customers $104 million resulting from the severe winter weather events. SWEPCo worked with wholesale customers to establish payment terms for the outstanding accounts receivable. As of June 30, 2021, $63 million of accounts receivable from wholesale customers are outstanding. Management believes these receivables are probable of future collection.

PSO and SWEPCo Cash Flow Implications

PSO and SWEPCo evaluated financing alternatives to address the timing difference between the payment of the estimated natural gas expenses and purchases of electricity to suppliers and subsequent recovery from customers. In March 2021, PSO drew $100 million on its revolving credit facility and SWEPCo issued $500 million of Senior Unsecured Notes. In March 2021, Parent entered into a $500 million 364-day Term Loan and borrowed the full amount. The proceeds from this loan were used to help fund capital contributions to PSO and SWEPCo totaling $425 million and $100 million, respectively. In April 2021, PSO received an additional capital contribution from Parent of $125 million to further address these costs.

Although the February 2021 severe winter weather did not materially impact AEP's results of operations for the three and six months ended June 30, 2021, if either PSO or SWEPCo is unable to recover these fuel and purchased power costs, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.

COVID-19 Pandemic

During 2020, AEP's electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, AEP's state regulators also imposed temporary moratoria on customary disconnection practices. As of June 30, 2021, AEP's electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the third quarter of 2021. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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

AEP Texas Interim Transmission and Distribution Rates

Through June 30, 2021, AEP Texas' cumulative revenues from interim base rate increases that are subject to review is approximately $171 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 3, 2024.


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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 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top).

In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo's closed coal-fired generation assets, (b) the Virginia SCC's use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo's 2017 - 2019 earnings test and (c) the reasonableness and prudency of APCo's investments in AMI meters.

In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo's going-forward rates and (b) the Virginia SCC's decision to deny APCo tariff changes that align rates with underlying costs. For APCo's going-forward rates, APCo requested that the Virginia SCC clarify its final order and clarify whether APCo's current rates will allow it to earn a fair return. If the Virginia SCC's order did conclude on APCo's ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates.

In March 2021, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC's cost or the market price for nonaffiliated power.

In March 2021, APCo filed its assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo's decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo's rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo's depreciation expense for purposes of calculating APCo's earnings for the 2017-2019 triennial period.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor's recommendation that APCo's AMI costs incurred during the triennial period be disallowed, the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. APCo expects to submit its brief before the Virginia Supreme Court in the third quarter of 2021.

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In April 2021, and in conjunction with APCo's November 2020 and March 2021 appeals with the Virginia Supreme Court, APCo filed a petition for interim rates with the Virginia Supreme Court (subject to refund with interest and supported by a bond issuance) requesting a $40 million increase in annual APCo Virginia base rates. APCo submitted this filing based on Virginia law that allows the Virginia Supreme Court to authorize interim rates until the final disposition on APCo's appeals. APCo also requested an expedited schedule from the Virginia Supreme Court on APCo's appeals. In May 2021, the Virginia Supreme Court denied APCo's petition for an interim rate increase and denied the request for an expedited schedule on APCo's appeals.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo's request for proper treatment of the closed coal-fired plant assets in APCo's 2017-2019 triennial period, reducing APCo's earnings below the bottom of its authorized ROE band. If APCo's appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. The initial negative impact for the write-off of closed coal-fired plant asset balances would potentially be partially offset by an increase in base rates for earning below APCo's 2017-2019 authorized ROE band.

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. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, APCo close these generating facilities at the end of 2028. In July 2021, a Virginia Senior Hearing Examiner recommended that the Virginia SCC deny, at this time, APCo's request for approval of the ELG investments at the Amos and Mountaineer Plants. The examiner also recommended that if the Virginia SCC ultimately does not grant APCo approval of the ELG investments, the Virginia SCC should delay consideration of the reasonableness and prudency of previously incurred ELG costs until a future case.

APCo's current estimate of its total CCR/ELG cost of investment for the Amos and Mountaineer plants, including AFUDC, is approximately $240 million. As of June 30, 2021, APCo's total company CCR and ELG investment balances in CWIP for these plants were $8 million and $28 million, respectively.

If any of APCo's CCR/ELG costs are not approved for recovery, it would 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 June 30, 2021, AEP's share of ETT's cumulative revenues that are subject to review is approximately $1.3 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. ETT is required to file for a comprehensive rate review no later than February 1, 2023, during which the $1.3 billion of cumulative revenues above will be subject to review.
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I&M Rate Matters(Applies to AEP and I&M)

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 July 2021, I&M will submit its FAC filing and earnings test evaluation for the period ended May 2021. As of June 30, 2021, 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.

2021 Indiana Base Rate Case

In July 2021, I&M filed a request with the IURC for a $104 million annual increase in Indiana base rates based upon a proposed 10% ROE. I&M proposed a phased-in annual increase in rates of $73 million effective in May 2022 with the remaining $31 million annual increase in rates to be effective January 2023. The proposed annual increase includes $7 million related to an annual increase in depreciation expense, driven by increased depreciation rates and proposed investments. The request also includes a new AMI rider for proposed meter projects. Intervenor testimony is expected in the fourth quarter of 2021. If any costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters(Applies to AEP)

CCR/ELG Compliance Plan Filings

KPCo and WPCo each own a 50% interest in the Mitchell Plant. 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 through 2040. 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 May 2021, intervenors in Kentucky and West Virginia submitted testimony with recommendations that only the CCR-related investments be constructed at the Mitchell Plant. In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. As of June 30, 2021, the total of the Mitchell Plant CCR and ELG investment balances in CWIP, was $2 million and $4 million, respectively, split equally between KPCo and WPCo. As of June 30, 2021, the net book value of the Mitchell Plant, before cost of removal including CWIP and inventory, was $1.2 billion, split equally between KPCo and WPCo.

If any of the CCR and ELG compliance plan costs are not approved for recovery and/or the retirement date of the Mitchell Plant is accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

OPCo Rate Matters(Applies to AEP and OPCo)

2020 Ohio Base Rate Case

In June 2020, OPCo filed a request with the PUCO for a $42 million annual increase in base rates based upon a proposed 10.15% ROE net of existing riders. Additionally, OPCo filed a request with the PUCO for a 60-day temporary delay of the normal rate case proceeding due to the COVID-19 pandemic with rates expected to be effective approximately mid-2021.
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In November 2020, the PUCO staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon an ROE of 8.76% to 9.78%. The difference between OPCo's request and the staff testimony are primarily due to reductions in: (a) demand-side management programs of $40 million, (b) ROE ranging from $9 million to $30 million, (c) employee-related expenses of $23 million, (d) rate base of $19 million, (e) property taxes of $17 million, (f) other various expenses of $15 million, (g) depreciation expense of $11 million and (h) vegetation management programs of $10 million which is subject to over/under-recovery through a rider. The staff's proposed disallowance of plant in service could also result in a write-off of up to $27 million. In addition, the staff recommended that capitalized incentives be excluded from base rates prospectively and also recommended annual revenue caps for the DIR of $57 million in 2021, $78 million in 2022, $96 million in 2023 and $46 million for the first five months of 2024. In December 2020, OPCo and intervenors filed objections.

In March 2021, OPCo, the PUCO staff and various intervenors filed a joint stipulation and settlement agreement with the PUCO. The agreement includes a $68 million annual decrease in base rates based on an ROE of 9.7%. The difference between OPCo's requested annual base rate increase and the agreed upon decrease is primarily due to a reduction in the requested ROE, the removal of proposed future energy efficiency costs and a decrease in vegetation management expenses moved to recovery in riders. Additionally, the agreement includes: (a) an increased fixed monthly residential customer charge, (b) the discontinuation of rate decoupling and (c) the continuation of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023 and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increased if OPCo achieves certain reliability standards. If the joint stipulation and settlement agreement is approved by the PUCO, new base rates will go into effect 14 days after such approval. A hearing took place with the PUCO in May 2021 and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected by the end of 2021. If the joint stipulation and settlement agreement is denied by the PUCO, it could reduce future net income and cash flows and impact financial condition.

2019 Ohio DIR Audit

OPCo conducts business under an ESP as approved by the PUCO which subjects the DIR to annual audits. In August 2020, a third-party consulting company filed an audit report with the PUCO indicating that OPCo exceeded its 2019 authorized revenue limit by $17 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. The PUCO has not yet issued a procedural schedule to address the audit results. If the results of the audit are upheld by the PUCO and any refunds to customers or revenue reductions are ordered, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters(Applies to AEP and PSO)

2021 Oklahoma Base Rate Case

In April 2021, PSO filed a request with the OCC for a $172 million net annual increase in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense increase, of which $45 million is related to the accelerated depreciation recovery of the Oklaunion Power Station and Northeastern Plant, Unit 3 through 2026 and (b) $31 million related to increased SPP expenses. PSO also requested the continuation of its SPP Transmission Tariff that tracks transmission costs as well as continuation and expansion of its Distribution and Safety Reliability Rider to recover projects in its proposed grid transformation and revitalization plan, which includes $100 million annual capital spend over a 5 year period. Intervenor testimony is expected in the third quarter of 2021. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
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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. The resulting annual base rate increase was approximately $52 million. 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. SWEPCo awaits a decision on the AFUDC dispute from the Texas Third Court of Appeals.

As of June 30, 2021, the net book value of Turk Plant was $1.4 billion, before cost of removal, including materials and supplies inventory and CWIP. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately fully recover its approximate 33% Texas jurisdictional share of the Turk Plant AFUDC, it could reduce future net income and cash flows and impact financial condition.

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. 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.

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Hurricane Laura

In August 2020, Hurricane Laura hit the coasts of Louisiana and Texas, causing power outages to more than 130,000 customers across SWEPCo's service territories. Prior to Hurricane Laura, SWEPCo did not have a catastrophe reserve or automatic deferral authority within any of its jurisdictions. In October 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Laura. In October 2020, as part of the 2020 Texas Base Rate Case, SWEPCo requested deferral authority of incremental other operation and maintenance expenses. As of June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $83 million ($81 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $30 million, all of which is related to the Louisiana jurisdiction. Management expects to request recovery of these storm costs, in addition to the Hurricane Delta and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Laura are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Hurricane Delta

In October 2020, Hurricane Delta hit the coast of Louisiana, causing power outages to more than 23,000 customers in SWEPCo's Louisiana jurisdiction. In November 2020, the LPSC issued an order allowing Louisiana utilities, including SWEPCo, to establish a regulatory asset to track and defer expenses associated with Hurricane Delta. As of June 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $17 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $3 million. Management expects to request recovery of these storm costs, in addition to the Hurricane Laura and February 2021 winter storm costs, in a future filing. If any costs related to Hurricane Delta are not recoverable, 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. The proposed net annual increase: (a) includes $5 million related to vegetation management to maintain and improve the reliability of SWEPCo's Texas jurisdictional distribution system, (b) requests a $10 million annual depreciation increase and (c) seeks $2 million annually to establish a storm catastrophe reserve. In addition, SWEPCo requested recovery of the Texas jurisdictional share of the Dolet Hills Power Station of $45 million which is expected to be retired by the end of 2021. In March 2021, intervenor testimony was filed supporting an annual revenue increase ranging from $20 million to $70 million based upon an ROE of 9% to 9.15%. In April 2021, staff testimony was filed supporting a $45 million annual increase in base rates based upon an ROE of 9.22%. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

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. In March 2021, SWEPCo filed a revised request with the LPSC to remove hurricane storm costs from the base rate case filing and seek recovery of those costs in a separate filing. SWEPCo's revised filing requested an annual increase in Louisiana base rates of $114 million. The request would extend the formula rate plan for five years and includes modifications to the formula rate plan to allow for forward-looking transmission costs, reflects the impact of net operating losses associated with the acceleration of certain tax benefits and incorporates future federal corporate income tax changes. The proposed net annual increase requests a $32 million annual depreciation increase to recover Louisiana's share of the Dolet Hills Power Station, Pirkey Power Plant and Welsh Plant, all of which are expected to be retired early. In April 2021, the LPSC approved
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SWEPCo's request to remove the hurricane storm costs from the base rate case filing. Management expects to request recovery of the $144 million of storm costs associated with Hurricanes Delta, Laura and the February 2021 winter storm in a separate filing.

In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon an ROE of 9.1% while other intervenors recommended an ROE ranging from 9.35% to 9.8%. The primary differences between SWEPCo's requested annual increase in base rates and the LPSC staff's recommendation include: (a) a reduction in depreciation expense, (b) recovery of Dolet Hills Power Station and Pirkey Power Plant in a separate rider mechanism, (c) the rejection of SWEPCo's proposed adjustment to include a stand-alone net operating loss carryforward deferred tax asset in rate base and (d) a reduction in the proposed ROE. SWEPCo expects to file rebuttal testimony in the third quarter of 2021.

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

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. Management is currently reviewing the formal challenge and responses are due to the FERC at the end of July 2021. If the FERC orders revenue refunds or reductions, it could reduce future net income and cash flows and impact financial condition.

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 (RTEP) to alleviate congestion. Transource Energy owns 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 (PA PUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania, which is currently pending. The IEC currently remains in the PJM RTEP and as of June 30, 2021, AEP's share of IEC capital expenditures is approximately $77 million. 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.
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5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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

The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants' business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2020 Annual Report should be read in conjunction with this report.

GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for 'Guarantees.' There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

Letters of Credit (Applies to AEP and AEP Texas)

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 service reserves.

AEP has $4 billion and $1 billion revolving credit facilities due in March 2026 and 2023, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of June 30, 2021, no letters of credit were issued under the revolving credit facility.

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 six uncommitted facilities totaling $425 million. The Registrants' maximum future payments for letters of credit issued under the uncommitted facilities as of June 30, 2021 were as follows:
Company Amount Maturity
(in millions)
AEP $ 186.5 July 2021 to July 2022
AEP Texas (a) 2.2 July 2022
(a) In July 2021, the maturity date was extended from July 2021 to July 2022.

Guarantees of Equity Method Investees (Applies to AEP)

In 2019, AEP acquired Sempra Renewables LLC. The transaction resulted in the acquisition of a 50% ownership interest in five non-consolidated joint ventures and the acquisition of two tax equity partnerships. Parent has issued guarantees over the performance of the joint ventures. If a joint venture were to default on payments or performance, Parent would be required to make payments on behalf of the joint venture. As of June 30, 2021, the
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maximum potential amount of future payments associated with these guarantees was $148 million, with the last guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $29 million, with an additional $1 million expected credit loss liability for the contingent portion of the guarantees. Management considered historical losses, economic conditions and reasonable and supportable forecasts in the calculation of the expected credit loss. As the joint ventures generate cash flows through PPAs, the measurement of the contingent portion of the guarantee liability is based upon assessments of the credit quality and default probabilities of the respective PPA counterparties.

Indemnifications and Other Guarantees

Contracts

The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of June 30, 2021, there were no material liabilities recorded for any indemnifications.

AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf. AEPSC also conducts power purchase-and-sale activity on behalf of PSO and SWEPCo, who are jointly and severally liable for activity conducted on their behalf.

Master Lease Agreements (Applies to all Registrants except AEPTCo)

The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of June 30, 2021, the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
Company Maximum
Potential Loss
(in millions)
AEP $ 48.6
AEP Texas 11.4
APCo 6.3
I&M 4.2
OPCo 7.6
PSO 4.7
SWEPCo 5.3

Rockport Lease (Applies to AEP and I&M)

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The Owner Trustee owns the Plant and leases equal portions to AEGCo and I&M. The lease is accounted for as an operating lease. The lease term is for 33 years and at the end of the lease term, AEGCo and I&M have the option to renew the lease at a rate that approximates fair value. In November 2020, management announced that AEP will not renew the lease when it expires in 2022. AEP, AEGCo and I&M have no ownership interest in the Owner
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Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of June 30, 2021 were as follows:
Future Minimum Lease Payments AEP (a) I&M
(in millions)
2021 $ 74.0 $ 37.0
2022 147.6 73.8
Total Future Minimum Lease Payments $ 221.6 $ 110.8

(a)AEP's future minimum lease payments include equal shares from AEGCo and I&M.

AEPRO Boat and Barge Leases (Applies to AEP)

In 2015, AEP sold its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. Certain boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the respective lessors, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2021, the maximum potential amount of future payments required under the guaranteed leases was $45 million. Under the terms of certain of the arrangements, upon the lessors exercising their rights after an event of default by the nonaffiliated party, AEP is entitled to enter into new lease arrangements as a lessee that would have substantially the same terms as the existing leases. Alternatively, for the arrangements with one of the lessors, upon an event of default by the nonaffiliated party and the lessor exercising its rights, payment to the lessor would allow AEP to step into the lessor's rights as well as obtaining title to the assets. Under either situation, AEP would have the ability to utilize the assets in the normal course of barging operations. AEP would also have the right to sell the acquired assets for which it obtained title. As of June 30, 2021, AEP's boat and barge lease guarantee liability was $3 million, of which $1 million was recorded in Other Current Liabilities and $2 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP's balance sheets.

In February 2020, the nonaffiliated party filed Chapter 11 bankruptcy. The party entered into a restructuring support agreement and has announced it expected to continue their operations as normal. In March 2020, the bankruptcy court approved the party's recapitalization plan. In April 2020, the nonaffiliated party emerged from bankruptcy. Management has determined that it is reasonably possible that enforcement of AEP's liability for future payments under these leases will be exercised within the next twelve months. In such an event, if AEP is unable to sell or incorporate any of the acquired assets into its fleet operations, it could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL CONTINGENCIES (Applies to all Registrants except AEPTCo)

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. The Registrants currently incur costs to dispose of these substances safely. For remediation processes not specifically discussed, management does not anticipate that the liabilities, if any, arising from such remediation processes would have a material effect on the financial statements.

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NUCLEAR CONTINGENCIES (Applies to AEP and I&M)

I&M owns and operates the Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

OPERATIONAL CONTINGENCIES

Rockport Plant Litigation (Applies to AEP and I&M)

In 2013, the Wilmington Trust Company filed a complaint 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 seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.

AEGCo and I&M sought and were granted dismissal by the U.S. District Court for the Southern District of Ohio of certain of the plaintiffs' claims, including claims for compensatory damages, breach of contract, breach of the implied covenant of good faith and fair dealing and indemnification of costs. Plaintiffs voluntarily dismissed the surviving claims that AEGCo and I&M failed to exercise prudent utility practices with prejudice, and the court issued a final judgment. The plaintiffs subsequently filed an appeal in the U.S. Court of Appeals for the Sixth Circuit.

In 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion and judgment affirming the district court's dismissal of the owners' breach of good faith and fair dealing claim as duplicative of the breach of contract claims, reversing the district court's dismissal of the breach of contract claims and remanding the case for further proceedings.

Thereafter, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking to modify the consent decree. The district court granted the owners' unopposed motion to stay the lease litigation to afford time for resolution of AEP's motion to modify the consent decree. The consent decree was modified based on an agreement among the parties in July 2019. The district court's stay of the lease litigation expired in August 2020. Upon expiration of the stay, plaintiffs filed a motion for partial summary judgment, arguing that the consent decree violates the facility lease and the participation agreement and requesting that the district court enter a judgment for the plaintiffs on their breach of contract claim. AEP's memorandum in opposition to plaintiffs' motion for partial summary judgment was filed in October 2020. At the parties' request, the district court stayed the case until April 19, 2021 to provide the parties an opportunity to resolve the case.

On April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5 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, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. As a result, in May 2021, at the parties request, the district court entered a stipulation and order dismissing the case without prejudice to plaintiffs asserting their claims in a re-filed action or a new action. The agreement is subject to customary closing conditions, including regulatory approvals, and as of the closing will result in a final settlement of, and release of claims in, the lease litigation. Management believes its financial statements appropriately reflect the expected resolution of the pending litigation.
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Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

The American Electric Power System Retirement Plan (the Plan) has received a letter written on behalf of four participants (the Claimants) making a claim for additional plan benefits and purporting to advance such claims on behalf of a class. 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 Claimants have asserted claims 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) the company failed to provide required notice regarding the changes to the Plan. AEP has responded to the Claimants providing a reasoned explanation for why each of their claims have been denied. The denial of those claims was appealed to the AEP System Retirement Plan Appeal Committee and the Committee upheld the denial of claims. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

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, the Company, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We do 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 United States District Court for the Southern District of Ohio against AEP and certain of its officers for alleged violations of securities laws. The amended complaint alleges 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 seeks monetary damages, among other forms of relief. On May 10, 2021, the defendants filed a motion to dismiss the securities litigation for failure to state a claim, and under the Court's briefing schedule the motion will be fully briefed by July 26, 2021. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In January 2021, an AEP shareholder filed a derivative action in the United States 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 first three derivative actions have been stayed pending the resolution of the motion to dismiss the securities litigation. The fourth has been stayed until such time as the court determines to lift the stay. The company will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

On March 1, 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
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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, the Company commence a civil action for breaches of fiduciary duty and related claims and take appropriate disciplinary action against those individuals who allegedly harmed the company. The shareholder that sent the letter has agreed that AEP and the AEP Board may defer consideration of the litigation demand until the resolution of the motion to dismiss the securities litigation. The AEP Board will act in response to the letter as appropriate. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

In May 2021, AEP received a subpoena from the SEC's Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP's financial processes and controls. AEP is cooperating fully with the SEC's subpoena. Although we cannot predict the outcome of the SEC's investigation, we do not believe the results of this inquiry will have a material impact on our financial condition, results of operations, or cash flows.
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6. ACQUISITIONS AND DISPOSITIONS

The disclosures in this note apply to AEP unless indicated otherwise.

ACQUISITIONS

Dry Lake Solar Project (Generation & Marketing Segment)

In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the 100 MW Dry Lake Solar Project (Dry Lake) located in southern Nevada for approximately $114 million. In March 2021, AEP closed the transaction and the solar project was placed in-service in May 2021. Approximately $103 million of the purchase price was paid upon closing of the transaction and the remaining $11 million was paid when the project was placed in-service. In accordance with the accounting guidance for 'Business Combinations,' management determined that the acquisition of Dry Lake represents an asset acquisition. Additionally, and in accordance with the accounting guidance for 'Consolidation,' management concluded that Dry Lake is a VIE and that AEP is the primary beneficiary based on its power as managing member to direct the activities that most significantly impact Dry Lake's economic performance. As the primary beneficiary of Dry Lake, AEP consolidates Dry Lake into its financial statements. As a result, to account for the initial consolidation of Dry Lake, management applied the acquisition method by allocating the purchase price based on the relative fair value of the assets acquired and noncontrolling interest assumed. The fair value of the primary assets acquired and the noncontrolling interest assumed was determined using the market approach. The key input assumptions were the transaction price paid for AEP's interest in Dry Lake and recent third-party market transactions for similar solar generation facilities. The nonaffiliated interest in Dry Lake is presented in Noncontrolling Interests on the balance sheets. Subsequent to close of the transaction, the noncontrolling interest made additional asset contributions of $14 million. As of June 30, 2021, AEP recognized approximately $146 million of Property, Plant and Equipment and approximately $33 million of Noncontrolling Interest on the balance sheets.

North Central Wind Energy Facilities (Vertically Integrated Utilities Segment) (Applies to AEP, PSO and SWEPCo)

In 2020, PSO and SWEPCo received regulatory approvals to acquire the North Central Wind Energy Facilities (NCWF), comprised of three Oklahoma wind facilities totaling 1,485 MWs, on a fixed cost turn-key basis at completion. PSO and SWEPCo will own undivided interests of 45.5% and 54.5% of the NCWF, respectively. In total, the three wind facilities will cost approximately $2 billion and consist of Traverse (999 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serve 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 mechanism to recover the Arkansas portion of the NCWF revenue requirement will be addressed in a future regulatory proceeding. The NCWF are subject to various regulatory performance requirements. If these performance requirements are not met, PSO and SWEPCo would recognize a regulatory liability to refund retail customers.

In April 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Sundance during its development and construction for $270 million, the first of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Sundance assets in proportion to their undivided ownership interests. Sundance was placed in-service in April 2021. The total investment in Sundance is estimated to be $291 million inclusive of previously capitalized pre-construction costs.

In accordance with the guidance for 'Business Combinations,' management determined that the acquisition of Sundance represents an asset acquisition. The initial consolidation of Sundance and subsequent distribution of its assets resulted in the recognition and initial measurement of acquisition costs of $123 million and $147 million in
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Property, Plant and Equipment on the balance sheets of PSO and SWEPCo, respectively. On an ongoing basis, management further determined that PSO and SWEPCo should apply the joint plant accounting model to account for their respective undivided interests in the assets, liabilities, revenues and expenses of Sundance.

The Purchase and Sale Agreement (PSA) includes collective interests in numerous land contracts, as originally executed between the nonaffiliated party and the respective owners of the properties as defined in the contracts. These contracts provide for easement and access rights to the land that Sundance was built upon. These interests as lessee in each of the land contracts were transferred to Sundance (and subsequently to PSO and SWEPCo) as a part of the closing of the PSA. As of June 30, 2021, the Noncurrent Obligations Under Operating Leases are $13 million and $15 million on the balance sheets for PSO and SWEPCo, respectively.

DISPOSITIONS

Conesville Plant (Generation & Marketing Segment)

In June 2020, AEP and a nonaffiliated joint-owner executed an Environmental Liability and Property Transfer and Asset Purchase Agreement with a nonaffiliated third-party related to the merchant Conesville Plant site. The purchaser took ownership of the assets and assumed responsibility for environmental liabilities, including ash pond closure, asbestos abatement and decommissioning and demolition of the Conesville Plant site. In consideration of the transfer of the acquired assets to the purchaser and the purchaser's assumption of liabilities, AEP will pay a total of approximately $98 million over three years, derecognized $106 million in ARO and recorded an immaterial gain on the transaction which is recorded in Other Operation on the statements of income. AEP paid approximately $26 million at closing in June 2020 and made additional payments totaling $28 million in quarterly installments from October 2020 to April 2021. AEP will make additional payments totaling $44 million in quarterly installments from July 2021 to July 2022.
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7. BENEFIT PLANS

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

AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans:

AEP
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 32.3 $ 28.0 $ 2.4 $ 2.5
Interest Cost 34.3 41.9 7.6 10.0
Expected Return on Plan Assets (57.4) (66.2) (22.8) (24.0)
Amortization of Prior Service Credit - - (17.7) (17.5)
Amortization of Net Actuarial Loss 25.4 23.4 - 1.5
Net Periodic Benefit Cost (Credit) $ 34.6 $ 27.1 $ (30.5) $ (27.5)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 64.6 $ 56.0 $ 4.8 $ 5.0
Interest Cost 68.6 83.9 15.2 19.9
Expected Return on Plan Assets (114.9) (132.4) (45.6) (47.9)
Amortization of Prior Service Credit - - (35.4) (34.9)
Amortization of Net Actuarial Loss 50.8 46.8 - 3.0
Net Periodic Benefit Cost (Credit) $ 69.1 $ 54.3 $ (61.0) $ (54.9)


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AEP Texas
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 2.9 $ 2.4 $ 0.1 $ 0.2
Interest Cost 2.8 3.5 0.6 0.8
Expected Return on Plan Assets (4.8) (5.7) (1.8) (2.0)
Amortization of Prior Service Credit - - (1.5) (1.6)
Amortization of Net Actuarial Loss 2.0 2.0 - 0.2
Net Periodic Benefit Cost (Credit) $ 2.9 $ 2.2 $ (2.6) $ (2.4)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 5.9 $ 5.0 $ 0.3 $ 0.4
Interest Cost 5.6 7.0 1.2 1.6
Expected Return on Plan Assets (9.7) (11.4) (3.7) (4.0)
Amortization of Prior Service Credit - - (3.0) (3.0)
Amortization of Net Actuarial Loss 4.1 3.9 - 0.3
Net Periodic Benefit Cost (Credit) $ 5.9 $ 4.5 $ (5.2) $ (4.7)

APCo
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 2.9 $ 2.6 $ 0.2 $ 0.2
Interest Cost 4.1 5.1 1.2 1.7
Expected Return on Plan Assets (7.2) (8.4) (3.3) (3.7)
Amortization of Prior Service Credit - - (2.6) (2.6)
Amortization of Net Actuarial Loss 3.0 2.8 - 0.3
Net Periodic Benefit Cost (Credit) $ 2.8 $ 2.1 $ (4.5) $ (4.1)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 5.9 $ 5.2 $ 0.5 $ 0.5
Interest Cost 8.2 10.2 2.4 3.3
Expected Return on Plan Assets (14.5) (16.8) (6.7) (7.3)
Amortization of Prior Service Credit - - (5.2) (5.1)
Amortization of Net Actuarial Loss 6.0 5.6 - 0.5
Net Periodic Benefit Cost (Credit) $ 5.6 $ 4.2 $ (9.0) $ (8.1)
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I&M
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 4.3 $ 3.8 $ 0.3 $ 0.4
Interest Cost 4.1 4.9 0.9 1.1
Expected Return on Plan Assets (7.2) (8.3) (2.8) (2.9)
Amortization of Prior Service Credit - - (2.4) (2.4)
Amortization of Net Actuarial Loss 3.0 2.7 - 0.2
Net Periodic Benefit Cost (Credit) $ 4.2 $ 3.1 $ (4.0) $ (3.6)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 8.7 $ 7.7 $ 0.6 $ 0.7
Interest Cost 8.1 9.8 1.8 2.3
Expected Return on Plan Assets (14.4) (16.6) (5.6) (5.8)
Amortization of Prior Service Credit - - (4.8) (4.8)
Amortization of Net Actuarial Loss 5.9 5.4 - 0.4
Net Periodic Benefit Cost (Credit) $ 8.3 $ 6.3 $ (8.0) $ (7.2)

OPCo
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 2.8 $ 2.4 $ 0.2 $ 0.3
Interest Cost 3.1 3.8 0.8 1.1
Expected Return on Plan Assets (5.5) (6.5) (2.5) (2.7)
Amortization of Prior Service Credit - - (1.8) (1.7)
Amortization of Net Actuarial Loss 2.3 2.2 - 0.1
Net Periodic Benefit Cost (Credit) $ 2.7 $ 1.9 $ (3.3) $ (2.9)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 5.7 $ 4.8 $ 0.4 $ 0.5
Interest Cost 6.2 7.7 1.6 2.1
Expected Return on Plan Assets (11.1) (13.1) (4.9) (5.3)
Amortization of Prior Service Credit - - (3.6) (3.5)
Amortization of Net Actuarial Loss 4.5 4.3 - 0.3
Net Periodic Benefit Cost (Credit) $ 5.3 $ 3.7 $ (6.5) $ (5.9)


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PSO
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 2.1 $ 1.8 $ 0.1 $ 0.1
Interest Cost 1.6 2.2 0.4 0.5
Expected Return on Plan Assets (3.1) (3.7) (1.2) (1.3)
Amortization of Prior Service Credit - - (1.1) (1.1)
Amortization of Net Actuarial Loss 1.2 1.2 - 0.1
Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.5 $ (1.8) $ (1.7)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 4.0 $ 3.6 $ 0.3 $ 0.3
Interest Cost 3.3 4.3 0.8 1.0
Expected Return on Plan Assets (6.2) (7.3) (2.5) (2.6)
Amortization of Prior Service Credit - - (2.2) (2.2)
Amortization of Net Actuarial Loss 2.5 2.4 - 0.2
Net Periodic Benefit Cost (Credit) $ 3.6 $ 3.0 $ (3.6) $ (3.3)

SWEPCo
Pension Plans OPEB
Three Months Ended June 30, Three Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 2.8 $ 2.4 $ 0.2 $ 0.2
Interest Cost 2.1 2.6 0.5 0.7
Expected Return on Plan Assets (3.4) (3.9) (1.5) (1.7)
Amortization of Prior Service Credit - - (1.3) (1.3)
Amortization of Net Actuarial Loss 1.6 1.4 - 0.1
Net Periodic Benefit Cost (Credit) $ 3.1 $ 2.5 $ (2.1) $ (2.0)
Pension Plans OPEB
Six Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Service Cost $ 5.7 $ 4.9 $ 0.3 $ 0.4
Interest Cost 4.2 5.1 1.0 1.3
Expected Return on Plan Assets (6.8) (7.8) (3.0) (3.2)
Amortization of Prior Service Credit - - (2.6) (2.6)
Amortization of Net Actuarial Loss 3.1 2.8 - 0.2
Net Periodic Benefit Cost (Credit) $ 6.2 $ 5.0 $ (4.3) $ (3.9)
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8. BUSINESS SEGMENTS

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

AEP's Reportable Segments

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

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

Generation & Marketing

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

The remainder of AEP's activities is 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, interest expense, income tax expense and other nonallocated costs.
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The tables below present AEP's reportable segment income statement information for the three and six months ended June 30, 2021 and 2020 and reportable segment balance sheet information as of June 30, 2021 and December 31, 2020.
Three Months Ended June 30, 2021
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 2,224.6 $ 1,089.6 $ 86.4 $ 422.5 $ 3.4 $ - $ 3,826.5
Other Operating Segments
36.0 13.8 291.8 14.1 12.1 (367.8) -
Total Revenues $ 2,260.6 $ 1,103.4 $ 378.2 $ 436.6 $ 15.5 $ (367.8) $ 3,826.5
Net Income (Loss)
$ 228.8 $ 153.7 $ 169.6 $ 46.5 $ (24.8) $ - $ 573.8
Three Months Ended June 30, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 2,062.3 $ 1,009.4 $ 69.2 $ 350.2 $ 2.9 $ - $ 3,494.0
Other Operating Segments
29.7 25.1 180.5 26.7 16.6 (278.6) -
Total Revenues $ 2,092.0 $ 1,034.5 $ 249.7 $ 376.9 $ 19.5 $ (278.6) $ 3,494.0
Net Income (Loss)
$ 256.3 $ 139.5 $ 92.2 $ 58.5 $ (32.0) $ - $ 514.5
Six Months Ended June 30, 2021
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 4,729.1 $ 2,171.9 $ 174.3 $ 1,024.2 $ 8.1 $ - $ 8,107.6
Other Operating Segments
68.8 19.6 580.9 46.6 20.3 (736.2) -
Total Revenues $ 4,797.9 $ 2,191.5 $ 755.2 $ 1,070.8 $ 28.4 $ (736.2) $ 8,107.6
Net Income (Loss)
$ 500.2 $ 268.1 $ 342.8 $ 84.7 $ (43.2) $ - $ 1,152.6
Six Months Ended June 30, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling Adjustments Consolidated
(in millions)
Revenues from:
External Customers
$ 4,255.3 $ 2,084.6 $ 142.3 $ 758.6 $ 0.7 $ - $ 7,241.5
Other Operating Segments
63.4 56.8 417.6 56.9 38.7 (633.4) -
Total Revenues $ 4,318.7 $ 2,141.4 $ 559.9 $ 815.5 $ 39.4 $ (633.4) $ 7,241.5
Net Income (Loss)
$ 502.6 $ 255.7 $ 233.8 $ 89.0 $ (67.3) $ - $ 1,013.8
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June 30, 2021
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling
Adjustments
Consolidated
(in millions)
Total Property, Plant and Equipment
$ 50,135.7 $ 21,833.8 $ 12,551.5 $ 2,122.5 $ 412.8 $ - $ 87,056.3
Accumulated Depreciation and Amortization
16,293.8 4,004.9 703.1 202.7 187.3 - 21,391.8
Total Property Plant and Equipment - Net
$ 33,841.9 $ 17,828.9 $ 11,848.4 $ 1,919.8 $ 225.5 $ - $ 65,664.5
Total Assets $ 45,225.0 $ 20,369.0 $ 13,231.7 $ 3,963.1 $ 5,766.8 (b) $ (4,197.4) (c) $ 84,358.2
Long-term Debt Due Within One Year:
Nonaffiliated $ 1,205.3 $ 789.9 $ 52.4 $ - $ 410.9 (d) $ - $ 2,458.5
Long-term Debt:
Affiliated 65.0 - - - - (65.0) -
Nonaffiliated 13,400.6 7,312.8 4,093.2 - 5,852.7 (d) - 30,659.3
Total Long-term Debt
$ 14,670.9 $ 8,102.7 $ 8,238.8 $ - $ 6,263.6 (d) $ (65.0) $ 33,117.8
December 31, 2020
Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation
&
Marketing
Corporate and Other (a) Reconciling
Adjustments
Consolidated
(in millions)
Total Property, Plant and Equipment
$ 49,023.3 $ 21,145.0 $ 11,827.2 $ 1,910.2 $ 407.3 $ - $ 84,313.0
Accumulated Depreciation and Amortization
15,586.2 3,879.3 595.7 166.1 184.1 - 20,411.4
Total Property Plant and Equipment - Net
$ 33,437.1 $ 17,265.7 $ 11,231.5 $ 1,744.1 $ 223.2 $ - $ 63,901.6
Total Assets $ 42,752.7 $ 19,765.9 $ 12,627.3 $ 3,585.9 $ 5,987.1 (b) $ (3,961.7) (c) $ 80,757.2
Long-term Debt Due Within One Year:
Nonaffiliated $ 1,034.6 $ 588.8 $ 52.3 $ - $ 410.4 (d) $ - $ 2,086.1
Long-term Debt:
Affiliated 65.0 - - - - (65.0) -
Nonaffiliated 12,375.6 6,661.9 4,075.7 - 5,873.2 (d) - 28,986.4
Total Long-term Debt
$ 13,475.2 $ 7,250.7 $ 4,128.0 $ - $ 6,283.6 (d) $ (65.0) $ 31,072.5

(a)Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income, interest expense and other nonallocated costs.
(b)Includes elimination of AEP Parent's investments in wholly-owned subsidiary companies.
(c)Reconciling Adjustments for Total Assets primarily include elimination of intercompany advances to affiliates and intercompany accounts receivable.
(d)Amounts are inclusive of the impact of fair value hedge accounting. See 'Accounting for Fair Value Hedging Strategies' section of Note 10 for additional information.


181




Registrant Subsidiaries' Reportable Segments (Applies to all Registrant Subsidiaries except AEPTCo)

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an integrated electricity transmission and distribution business for AEP Texas and OPCo. Other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

AEPTCo's Reportable Segments

AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities. The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for 'Segment Reporting.' The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the RTOs in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and provide service to AEP's wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by the FERC and earn revenues through tariff rates charged for the use of their electric transmission systems.

AEPTCo's Chief Operating Decision Maker makes operating decisions, allocates resources to and assesses performance based on these operating segments. The State Transcos operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for 'Segment Reporting' to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo's activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities.

The tables below present AEPTCo's reportable segment income statement information for the three and six months ended June 30, 2021 and 2020 and reportable segment balance sheet information as of June 30, 2021 and December 31, 2020.
Three Months Ended June 30, 2021
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$ 84.1 $ - $ - $ 84.1
Sales to AEP Affiliates
281.4 - - 281.4
Total Revenues $ 365.5 $ - $ - $ 365.5
Interest Income
$ - $ 38.4 $ (38.3) (a) $ 0.1
Interest Expense
34.3 38.2 (38.2) (a) 34.3
Income Tax Expense 39.1 - - 39.1
Net Income $ 148.5 $ 0.1 (b) $ - $ 148.6
Three Months Ended June 30, 2020
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Revenues from:
External Customers
$ 60.4 $ - $ - $ 60.4
Sales to AEP Affiliates
177.7 - - 177.7
Total Revenues $ 238.1 $ - $ - $ 238.1
Interest Income
$ 0.7 $ 38.9 $ (38.3) (a) $ 1.3
Interest Expense
32.8 38.3 (38.3) (a) 32.8
Income Tax Expense 19.2 0.1 - 19.3
Net Income $ 73.2 $ 0.5 (b) $ - $ 73.7
182




Six Months Ended June 30, 2021
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated
(in millions)
Revenues from:
External Customers $ 160.1 $ - $ - $ 160.1
Sales to AEP Affiliates 567.0 - - 567.0
Other Revenues 0.1 - - 0.1
Total Revenues $ 727.2 $ - $ - $ 727.2
Interest Income $ - $ 76.7 $ (76.5) (a) $ 0.2
Interest Expense 68.4 76.4 (76.4) (a) 68.4
Income Tax Expense 78.7 - - 78.7
Net Income $ 300.2 $ 0.1 (b) $ - $ 300.3
Six Months Ended June 30, 2020
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated
(in millions)
Revenues from:
External Customers $ 121.7 $ - $ - $ 121.7
Sales to AEP Affiliates 411.4 - - 411.4
Other Revenues 0.6 - - 0.6
Total Revenues $ 533.7 $ - $ - $ 533.7
Interest Income $ 0.9 $ 72.9 $ (71.7) (a) $ 2.1
Interest Expense 62.4 71.7 (71.7) (a) 62.4
Income Tax Expense 51.0 0.1 - 51.1
Net Income $ 190.5 $ 1.0 (b) $ - $ 191.5
June 30, 2021
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property $ 12,053.6 $ - $ - $ 12,053.6
Accumulated Depreciation and Amortization 677.1 - - 677.1
Total Transmission Property - Net $ 11,376.5 $ - $ - $ 11,376.5
Notes Receivable - Affiliated $ - $ 3,899.3 $ (3,899.3) (c) $ -
Total Assets $ 11,730.6 $ 4,083.6 (d) $ (4,023.9) (e) $ 11,790.3
Total Long-term Debt $ 3,990.0 $ 3,949.3 $ (3,990.0) (c) $ 3,949.3
December 31, 2020
State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo
Consolidated
(in millions)
Total Transmission Property
$ 11,345.6 $ - $ - $ 11,345.6
Accumulated Depreciation and Amortization
572.8 - - 572.8
Total Transmission Property - Net
$ 10,772.8 $ - $ - $ 10,772.8
Notes Receivable - Affiliated $ - $ 3,948.5 $ (3,948.5) (c) $ -
Total Assets $ 11,185.1 $ 4,084.0 (d) $ (4,023.1) (e) $ 11,246.0
Total Long-term Debt
$ 3,990.0 $ 3,948.5 $ (3,990.0) (c) $ 3,948.5

(a)Elimination of intercompany interest income/interest expense on affiliated debt arrangement.
(b)Includes the elimination of AEPTCo Parent's equity earnings in the State Transcos.
(c)Elimination of intercompany debt.
(d)Includes the elimination of AEPTCo Parent's investments in State Transcos.
(e)Primarily relates to the elimination of Notes Receivable from the State Transcos.
183




9. DERIVATIVES AND HEDGING

The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any derivative and hedging activity.

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries.

The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for 'Derivatives and Hedging.' Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as 'Commodity,' as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as 'Interest Rate.' 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.

184




The following tables represent the gross notional volume of the Registrants' outstanding derivative contracts:

Notional Volume of Derivative Instruments
June 30, 2021
Primary Risk
Exposure
Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:
Power MWhs 412.5 - 77.9 32.4 2.8 26.8 7.2
Natural Gas MMBtus 24.3 - - - - - 6.1
Heating Oil and Gasoline Gallons 9.7 2.5 1.5 0.9 1.9 1.1 1.3
Interest Rate
USD $ 123.6 $ - $ - $ - $ - $ - $ -
Interest Rate on Long-term Debt
USD $ 950.0 $ - $ - $ - $ - $ - $ -
December 31, 2020
Primary Risk
Exposure
Unit of
Measure
AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Commodity:
Power MWhs 331.3 - 46.9 19.7 3.0 11.9 4.0
Natural Gas MMBtus 26.9 - - - - - 7.9
Heating Oil and Gasoline Gallons 6.9 1.8 1.1 0.6 1.4 0.7 0.9
Interest Rate USD $ 129.8 $ - $ - $ - $ - $ - $ -
Interest Rate on Long-term Debt
USD $ 1,150.0 $ - $ 200.0 $ - $ - $ - $ -

Fair Value Hedging Strategies (Applies to AEP)

Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating-rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges.

Cash Flow Hedging Strategies

The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power ('Commodity') in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk.

The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure.
185




ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for 'Derivatives and Hedging' requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management's estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

According to the accounting guidance for 'Derivatives and Hedging,' the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The Registrants netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

June 30, 2021 December 31, 2020
Cash Collateral Cash Collateral Cash Collateral Cash Collateral
Received Paid Received Paid
Netted Against Netted Against Netted Against Netted Against
Risk Management Risk Management Risk Management Risk Management
Company Assets Liabilities Assets Liabilities
(in millions)
AEP $ 105.4 $ 12.4 $ 3.4 $ 6.8
APCo 0.7 5.3 0.4 -
I&M 0.3 4.5 1.7 -

Amounts for AEP Texas, OPCo, PSO and SWEPCo are immaterial as of June 30, 2021 and December 31, 2020, respectively.
186




The following tables represent the gross fair value of the Registrants' derivative activity on the balance sheets:

AEP
June 30, 2021
Risk
Management
Contracts
Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 441.7 $ 128.3 $ 3.2 $ 573.2 $ (358.5) $ 214.7
Long-term Risk Management Assets 276.6 52.8 - 329.4 (88.1) 241.3
Total Assets 718.3 181.1 3.2 902.6 (446.6) 456.0
Current Risk Management Liabilities 318.2 23.4 - 341.6 (293.8) 47.8
Long-term Risk Management Liabilities 229.7 18.0 28.4 276.1 (59.8) 216.3
Total Liabilities 547.9 41.4 28.4 617.7 (353.6) 264.1
Total MTM Derivative Contract Net Assets (Liabilities)
$ 170.4 $ 139.7 $ (25.2) $ 284.9 $ (93.0) $ 191.9

December 31, 2020
Risk
Management
Contracts
Hedging Contracts Gross Amounts
of Risk
Management
Assets/
Liabilities
Recognized
Gross
Amounts
Offset in the
Statement of
Financial
Position (b)
Net Amounts of
Assets/Liabilities
Presented in the
Statement of
Financial
Position (c)
Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (a)
(in millions)
Current Risk Management Assets $ 239.1 $ 21.1 $ 5.0 $ 265.2 $ (170.5) $ 94.7
Long-term Risk Management Assets 275.9 18.0 - 293.9 (51.7) 242.2
Total Assets 515.0 39.1 5.0 559.1 (222.2) 336.9
Current Risk Management Liabilities 193.0 54.4 3.4 250.8 (172.0) 78.8
Long-term Risk Management Liabilities 222.2 60.1 4.1 286.4 (53.6) 232.8
Total Liabilities 415.2 114.5 7.5 537.2 (225.6) 311.6
Total MTM Derivative Contract Net Assets (Liabilities)
$ 99.8 $ (75.4) $ (2.5) $ 21.9 $ 3.4 $ 25.3

187




AEP Texas
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 1.0 $ (1.0) $ -
Long-term Risk Management Assets 0.1 (0.1) -
Total Assets 1.1 (1.1) -
Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Contract Net Assets (Liabilities) $ 1.1 $ (1.1) $ -

December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.4 $ (0.4) $ -
Long-term Risk Management Assets - - -
Total Assets 0.4 (0.4) -
Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Contract Net Assets (Liabilities) $ 0.4 $ (0.4) $ -

188





APCo
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement
Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions)
Current Risk Management Assets $ 64.2 $ (27.1) $ 37.1
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.1 (0.1) -
Total Assets 64.3 (27.2) 37.1
Other Current Liabilities - Current Risk Management Liabilities 33.2 (31.8) 1.4
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities - - -
Total Liabilities 33.2 (31.8) 1.4
Total MTM Derivative Contract Net Assets $ 31.1 $ 4.6 $ 35.7

December 31, 2020
Gross Amounts
Risk of Risk Gross Amounts Net Amounts of Assets/
Management Hedging Management Offset in the Liabilities Presented in
Contracts - Contracts - Assets/Liabilities Statement of the Statement of
Balance Sheet Location Commodity (a) Interest Rate (a) Recognized Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 38.8 $ 2.4 $ 41.2 $ (18.8) $ 22.4
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.7 - 0.7 (0.6) 0.1
Total Assets 39.5 2.4 41.9 (19.4) 22.5
Other Current Liabilities - Current Risk Management Liabilities 19.7 3.4 23.1 (18.5) 4.6
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.6 - 0.6 (0.5) 0.1
Total Liabilities 20.3 3.4 23.7 (19.0) 4.7
Total MTM Derivative Contract Net Assets (Liabilities) $ 19.2 $ (1.0) $ 18.2 $ (0.4) $ 17.8
189




I&M
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 25.9 $ (18.2) $ 7.7
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets - - -
Total Assets 25.9 (18.2) 7.7
Current Risk Management Liabilities 23.5 (22.4) 1.1
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities - - -
Total Liabilities 23.5 (22.4) 1.1
Total MTM Derivative Contract Net Assets $ 2.4 $ 4.2 $ 6.6

December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 17.2 $ (13.6) $ 3.6
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets 0.5 (0.4) 0.1
Total Assets 17.7 (14.0) 3.7
Current Risk Management Liabilities 12.1 (12.0) 0.1
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities 0.4 (0.3) 0.1
Total Liabilities 12.5 (12.3) 0.2
Total MTM Derivative Contract Net Assets (Liabilities) $ 5.2 $ (1.7) $ 3.5

OPCo
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.7 $ (0.7) $ -
Long-term Risk Management Assets 0.1 (0.1) -
Total Assets 0.8 (0.8) -
Current Risk Management Liabilities 7.3 - 7.3
Long-term Risk Management Liabilities 98.2 - 98.2
Total Liabilities 105.5 - 105.5
Total MTM Derivative Contract Net Liabilities $ (104.7) $ (0.8) $ (105.5)

December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 0.3 $ (0.3) $ -
Long-term Risk Management Assets - - -
Total Assets 0.3 (0.3) -
Current Risk Management Liabilities 8.7 - 8.7
Long-term Risk Management Liabilities 101.6 - 101.6
Total Liabilities 110.3 - 110.3
Total MTM Derivative Contract Net Liabilities $ (110.0) $ (0.3) $ (110.3)
190




PSO
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 23.5 $ (0.5) $ 23.0
Long-term Risk Management Assets - - -
Total Assets 23.5 (0.5) 23.0
Other Current Liabilities - Current Risk Management Liabilities 0.2 (0.1) 0.1
Long-term Risk Management Liabilities - - -
Total Liabilities 0.2 (0.1) 0.1
Total MTM Derivative Contract Net Assets (Liabilities) $ 23.3 $ (0.4) $ 22.9

December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 10.5 $ (0.2) $ 10.3
Long-term Risk Management Assets - - -
Total Assets 10.5 (0.2) 10.3
Other Current Liabilities - Current Risk Management Liabilities - - -
Long-term Risk Management Liabilities - - -
Total Liabilities - - -
Total MTM Derivative Contract Net Assets (Liabilities) $ 10.5 $ (0.2) $ 10.3

SWEPCo
June 30, 2021
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 14.9 $ (0.9) $ 14.0
Long-term Risk Management Assets 0.7 (0.1) 0.6
Total Assets 15.6 (1.0) 14.6
Current Risk Management Liabilities 0.4 (0.4) -
Long-term Risk Management Liabilities - - -
Total Liabilities 0.4 (0.4) -
Total MTM Derivative Contract Net Assets (Liabilities) $ 15.2 $ (0.6) $ 14.6

December 31, 2020
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities
Contracts - in the Statement of Presented in the Statement of
Balance Sheet Location Commodity (a) Financial Position (b) Financial Position (c)
(in millions)
Current Risk Management Assets $ 3.4 $ (0.2) $ 3.2
Long-term Risk Management Assets - - -
Total Assets 3.4 (0.2) 3.2
Current Risk Management Liabilities 0.7 - 0.7
Long-term Risk Management Liabilities 1.0 - 1.0
Total Liabilities 1.7 - 1.7
Total MTM Derivative Contract Net Assets (Liabilities) $ 1.7 $ (0.2) $ 1.5

(a)Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for 'Derivatives and Hedging.'
(b)Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for 'Derivatives and Hedging.'
(c)All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
191




The tables below present the Registrants' amount of gain (loss) recognized on risk management contracts:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
Three Months Ended June 30, 2021
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.1 $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 16.5 - - - - - -
Electric Generation, Transmission and Distribution Revenues
- - 0.1 - - - -
Purchased Electricity for Resale 0.6 - 0.5 0.1 - - -
Other Operation 0.7 0.2 0.1 0.1 0.1 0.1 0.1
Maintenance 0.8 0.3 0.1 - 0.1 - 0.1
Regulatory Assets (a) (7.0) - - (5.1) (1.2) - 0.5
Regulatory Liabilities (a) 55.1 0.2 11.3 3.4 2.2 15.0 19.6
Total Gain (Loss) on Risk Management Contracts
$ 66.8 $ 0.7 $ 12.1 $ (1.5) $ 1.2 $ 15.1 $ 20.3

Three Months Ended June 30, 2020
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ (0.1) $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 9.9 - - - - - -
Electric Generation, Transmission and Distribution Revenues
- - (0.1) - - - 0.1
Purchased Electricity for Resale 0.8 - 0.7 - - - -
Other Operation (0.8) (0.2) (0.1) (0.1) (0.1) (0.1) (0.1)
Maintenance (1.2) (0.3) (0.1) (0.1) (0.2) (0.2) (0.2)
Regulatory Assets (a) 17.5 0.7 8.4 0.3 4.1 0.3 1.3
Regulatory Liabilities (a) 52.7 - 19.7 3.0 3.2 12.7 9.5
Total Gain on Risk Management Contracts $ 78.8 $ 0.2 $ 28.5 $ 3.1 $ 7.0 $ 12.7 $ 10.6

Six Months Ended June 30, 2021
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.3 $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues 16.1 - - - - - -
Electric Generation, Transmission and Distribution Revenues - - 0.3 - - - -
Purchased Electricity for Resale 1.0 - 0.9 0.1 - - -
Other Operation 1.0 0.3 0.1 0.1 0.2 0.1 0.1
Maintenance 1.3 0.4 0.2 0.1 0.2 0.1 0.2
Regulatory Assets (a) (0.6) - - (6.0) 5.4 - 1.3
Regulatory Liabilities (a) 77.1 0.6 14.7 0.2 5.1 26.2 25.8
Total Gain (Loss) on Risk Management Contracts $ 96.2 $ 1.3 $ 16.2 $ (5.5) $ 10.9 $ 26.4 $ 27.4
192




Six Months Ended June 30, 2020
Location of Gain (Loss) AEP AEP Texas APCo I&M OPCo PSO SWEPCo
(in millions)
Vertically Integrated Utilities Revenues $ 0.3 $ - $ - $ - $ - $ - $ -
Generation & Marketing Revenues (0.4) - - - - - -
Electric Generation, Transmission and Distribution Revenues - - 0.1 0.1 - - 0.1
Purchased Electricity for Resale 0.9 - 0.8 - - - -
Other Operation (1.0) (0.3) (0.1) (0.1) (0.2) (0.1) (0.1)
Maintenance (1.4) (0.4) (0.2) (0.1) (0.2) (0.2) (0.2)
Regulatory Assets (a) (16.4) (0.5) (0.5) (0.4) (14.3) (0.2) (0.7)
Regulatory Liabilities (a) 63.9 - 12.4 6.2 6.7 20.8 12.8
Total Gain (Loss) on Risk Management Contracts $ 45.9 $ (1.2) $ 12.5 $ 5.7 $ (8.0) $ 20.3 $ 11.9

(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for 'Derivatives and Hedging.' Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for 'Regulated Operations.'

Accounting for Fair Value Hedging Strategies (Applies to AEP)

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts net income during the period of change.

AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.


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The following table shows the impacts recognized on the balance sheets related to the hedged items in fair value hedging relationships:
Carrying Amount of the Hedged Liabilities Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities
June 30, 2021 December 31, 2020 June 30, 2021 December 31, 2020
(in millions)
Long-term Debt (a) (b) $ (967.4) $ (995.9) $ (24.2) $ (51.7)

(a)Amounts included on the balance sheets within Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(49) million and $(53) million as of June 30, 2021 and December 31, 2020, respectively, for the fair value hedge adjustment of hedged debt obligations for which hedge accounting has been discontinued.

The pretax effects of fair value hedge accounting on income were as follows:
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Gain (Loss) on Interest Rate Contracts:
Fair Value Hedging Instruments (a) $ 9.5 $ 0.1 $ (23.7) $ 42.6
Fair Value Portion of Long-term Debt (a) (9.5) (0.1) 23.7 (42.6)

(a)Gain (Loss) is included in Interest Expense on the statements of income.

In June 2020, AEP terminated a $500 million notional amount interest rate swap resulting in the discontinuance of the hedging relationship. A gain of $57 million on the fair value of the hedging instrument was settled in cash and recorded within operating activities on the statements of cash flows. Subsequent to the discontinuation of hedge accounting, the remaining adjustment to the carrying amount of the hedged item of $57 million will be amortized on a straight line basis through November 2027 in Interest Expense on the statements of income.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects net income.

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2021 and 2020, AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2021 and 2020, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives.

The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2021 and 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not.

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.


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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were:

Impact of Cash Flow Hedges on AEP's Balance Sheets
June 30, 2021 December 31, 2020
Commodity Interest Rate Commodity Interest Rate
(in millions)
AOCI Gain (Loss) Net of Tax $ 110.3 $ (32.2) $ (60.6) $ (47.5)
Portion Expected to be Reclassed to Net Income During the Next Twelve Months
82.9 (4.7) (27.1) (5.7)

As of June 30, 2021 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 117 months and 114 months for commodity and interest rate hedges, respectively.

Impact of Cash Flow Hedges on the Registrant Subsidiaries' Balance Sheets
June 30, 2021 December 31, 2020
Interest Rate
Expected to be Expected to be
Reclassified to Reclassified to
Net Income During Net Income During
AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next
Company Net of Tax Twelve Months Net of Tax Twelve Months
(in millions)
AEP Texas $ (1.8) $ (1.1) $ (2.3) $ (1.1)
APCo 8.0 0.8 (0.8) 0.4
I&M (7.4) (1.6) (8.3) (1.6)
PSO - - 0.1 0.1
SWEPCo 0.5 (0.8) (0.3) (1.5)

Amounts for OPCo are immaterial as of June 30, 2021 and December 31, 2020, respectively.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

Management mitigates credit risk 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.

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.


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Collateral Triggering Events

Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo)

A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering events in contracts. The Registrants have not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. AEP had six derivative contracts with collateral triggering events in a net liability position as of June 30, 2021, with a total exposure of $8 million. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of June 30, 2021. The Registrants had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2020.

Cross-Default Triggers (Applies to AEP, APCo, I&M and SWEPCo)

In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
June 30, 2021
Liabilities for Additional
Contracts with Cross Settlement
Default Provisions Liability if Cross
Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
(in millions)
AEP $ 118.4 $ - $ 70.2
APCo 0.6 - -
I&M 0.4 - -
SWEPCo - - -
December 31, 2020
Liabilities for Additional
Contracts with Cross Settlement
Default Provisions Liability if Cross
Prior to Contractual Amount of Cash Default Provision
Company Netting Arrangements Collateral Posted is Triggered
(in millions)
AEP $ 188.4 $ - $ 169.2
APCo 4.3 - 3.5
I&M 0.5 - 0.1
SWEPCo 1.8 - 1.8


196




Warrants Held in Investee (Applies to AEP)

AEP holds an investment in ChargePoint, which completed an initial public offering (IPO) in February 2021 via a reverse merger with a public special purpose acquisition company. Before the IPO, AEP's interests in ChargePoint consisted of a noncontrolling equity interest of preferred shares, which were accounted for at their historical cost of $8 million as of December 31, 2020, and common share warrants. After the IPO, AEP's interests in ChargePoint consisted of a noncontrolling equity interest of common shares, which were accounted for at their fair value of $46 million as of June 30, 2021, and common share warrants. AEP recorded an unrealized gain of $11 million and $38 million associated with the common shares for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP's statements of income.

Management has determined the common share warrants are derivative instruments based on the accounting guidance for 'Derivatives and Hedging'. As of June 30, 2021 and December 31, 2020, the warrants were valued at $26 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP's balance sheets. AEP recognized an unrealized gain (loss) of $4 million and $(6) million associated with the warrants for the three and six months ended June 30, 2021, respectively, presented in Other Income (Expense) on AEP's statements of income.

Management utilized a Black-Scholes options pricing model to value the warrants as of June 30, 2021 and December 31, 2020. The valuation contemplated a liquidity adjustment that resulted in the overall fair value of the warrants being categorized as Level 3 in the fair value hierarchy as of December 31, 2020. After the IPO, there was an observable publicly traded stock price to use in the Black-Scholes options pricing model, which resulted in the warrants being categorized as Level 2 as of June 30, 2021. The common shares are also categorized as Level 2 as management applied a discount to the shares due to a six month lock-up agreement post IPO. After the six month lock-up period, the common shares will be valued as Level 1 based on the publicly traded share prices. See 'Fair Value Measurements of Financial Assets and Liabilities' section of Note 10 for additional information.
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10. FAIR VALUE MEASUREMENTS

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

Fair Value Hierarchy and Valuation Techniques

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 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 nuclear trusts, cash and cash equivalents, other temporary investments 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 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.
198




Fair Value Measurements of Long-term Debt (Applies to all Registrants)

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value of AEP's Equity Units (Level 1) are valued based on publicly traded securities issued by AEP.

The book values and fair values of Long-term Debt are summarized in the following table:
June 30, 2021 December 31, 2020
Company Book Value Fair Value Book Value Fair Value
(in millions)
AEP (a) $ 33,117.8 $ 37,826.2 $ 31,072.5 $ 37,457.0
AEP Texas 5,226.0 5,809.5 4,820.4 5,682.6
AEPTCo 3,949.3 4,667.9 3,948.5 4,984.3
APCo 4,949.8 6,129.7 4,834.1 6,391.8
I&M 3,255.0 3,850.6 3,029.9 3,775.3
OPCo 2,876.8 3,419.0 2,430.2 3,154.9
PSO 1,623.8 1,883.6 1,373.8 1,732.1
SWEPCo 3,130.7 3,563.5 2,636.4 3,210.1

(a)The fair value amounts include debt related to AEP's Equity Units and had a fair value of $1.7 billion and $1.7 billion as of June 30, 2021 and December 31, 2020, respectively. See 'Equity Units' section of Note 12 for additional information.

Fair Value Measurements of Other Temporary Investments (Applies to AEP)

Other Temporary Investments include marketable securities that management intends to hold for less than one year and investments by AEP's protected cell of EIS.

The following is a summary of Other Temporary Investments:
June 30, 2021
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments Cost Gains Losses Value
(in millions)
Restricted Cash and Other Cash Deposits (a) $ 80.2 $ - $ - $ 80.2
Fixed Income Securities - Mutual Funds (b) 129.0 2.1 - 131.1
Equity Securities - Mutual Funds 22.7 34.7 - 57.4
Total Other Temporary Investments $ 231.9 $ 36.8 $ - $ 268.7
December 31, 2020
Gross Gross
Unrealized Unrealized Fair
Other Temporary Investments Cost Gains Losses Value
(in millions)
Restricted Cash and Other Cash Deposits (a) $ 68.3 $ - $ - $ 68.3
Fixed Income Securities - Mutual Funds (b) 120.7 2.8 - 123.5
Equity Securities - Mutual Funds 25.9 28.7 - 54.6
Total Other Temporary Investments $ 214.9 $ 31.5 $ - $ 246.4

(a)Primarily represents amounts held for the repayment of debt.
(b)Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
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The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Proceeds from Investment Sales $ 3.6 $ 7.6 $ 9.1 $ 30.8
Purchases of Investments 12.4 10.3 13.1 17.0
Gross Realized Gains on Investment Sales 1.1 0.2 1.2 2.2
Gross Realized Losses on Investment Sales - 0.1 - 0.2

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (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.

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.
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The following is a summary of nuclear trust fund investments:
June 30, 2021 December 31, 2020
Gross Other-Than- Gross Other-Than-
Fair Unrealized Temporary Fair Unrealized Temporary
Value Gains Impairments Value Gains Impairments
(in millions)
Cash and Cash Equivalents $ 35.6 $ - $ - $ 25.8 $ - $ -
Fixed Income Securities:
United States Government 1,155.8 68.9 (12.5) 1,025.6 98.5 (7.1)
Corporate Debt 87.3 7.1 (2.6) 86.3 9.6 (1.7)
State and Local Government 58.9 0.2 (0.6) 114.3 0.9 (0.4)
Subtotal Fixed Income Securities 1,302.0 76.2 (15.7) 1,226.2 109.0 (9.2)
Equity Securities - Domestic (a) 2,274.8 1,648.2 - 2,054.7 1,400.8 -
Spent Nuclear Fuel and Decommissioning Trusts
$ 3,612.4 $ 1,724.4 $ (15.7) $ 3,306.7 $ 1,509.8 $ (9.2)

(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.7 billion and $1.4 billion and unrealized losses of $3 million and $9 million as of June 30, 2021 and December 31, 2020, respectively.

The following table provides the securities activity within the decommissioning and SNF trusts:
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(in millions)
Proceeds from Investment Sales $ 802.7 $ 328.1 $ 1,122.7 $ 940.5
Purchases of Investments 812.8 345.4 1,149.7 971.4
Gross Realized Gains on Investment Sales 83.3 11.1 88.7 22.0
Gross Realized Losses on Investment Sales 1.3 7.7 5.5 24.7

The base cost of fixed income securities was $1.2 billion and $1.1 billion as of June 30, 2021 and December 31, 2020, respectively. The base cost of equity securities was $627 million and $654 million as of June 30, 2021 and December 31, 2020, respectively.

The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2021 was as follows:
Fair Value of Fixed
Income Securities
(in millions)
Within 1 year $ 331.4
After 1 year through 5 years 415.7
After 5 years through 10 years 263.0
After 10 years 291.9
Total $ 1,302.0
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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrants' financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for 'Fair Value Measurements and Disclosures,' financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.

AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a) $ 59.1 $ - $ - $ 21.1 $ 80.2
Fixed Income Securities - Mutual Funds 131.1 - - - 131.1
Equity Securities - Mutual Funds (b) 57.4 - - - 57.4
Total Other Temporary Investments 247.6 - - 21.1 268.7
Risk Management Assets
Risk Management Commodity Contracts (c) (d) 4.8 478.1 224.3 (400.1) 307.1
Cash Flow Hedges:
Commodity Hedges (c) - 158.7 16.9 (29.9) 145.7
Fair Value Hedges - 3.2 - - 3.2
Total Risk Management Assets 4.8 640.0 241.2 (430.0) 456.0
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 28.0 - - 7.6 35.6
Fixed Income Securities:
United States Government - 1,155.8 - - 1,155.8
Corporate Debt - 87.3 - - 87.3
State and Local Government - 58.9 - - 58.9
Subtotal Fixed Income Securities - 1,302.0 - - 1,302.0
Equity Securities - Domestic (b) 2,274.8 - - - 2,274.8
Total Spent Nuclear Fuel and Decommissioning Trusts 2,302.8 1,302.0 - 7.6 3,612.4
Other Investments (h) - 72.5 - - 72.5
Total Assets $ 2,555.2 $ 2,014.5 $ 241.2 $ (401.3) $ 4,409.6
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (d) $ 2.5 $ 395.2 $ 139.1 $ (307.1) $ 229.7
Cash Flow Hedges:
Commodity Hedges (c) - 35.0 0.9 (29.9) 6.0
Fair Value Hedges - 28.4 - - 28.4
Total Risk Management Liabilities $ 2.5 $ 458.6 $ 140.0 $ (337.0) $ 264.1
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AEP

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Other Temporary Investments
Restricted Cash and Other Cash Deposits (a) $ 57.8 $ - $ - $ 10.5 $ 68.3
Fixed Income Securities - Mutual Funds 123.5 - - - 123.5
Equity Securities - Mutual Funds (b) 54.6 - - - 54.6
Total Other Temporary Investments 235.9 - - 10.5 246.4
Risk Management Assets
Risk Management Commodity Contracts (c) (f) 0.9 258.8 252.4 (190.0) 322.1
Cash Flow Hedges:
Commodity Hedges (c) - 34.4 3.9 (28.5) 9.8
Interest Rate Hedges - 2.4 - - 2.4
Fair Value Hedges - 2.6 - - 2.6
Total Risk Management Assets 0.9 298.2 256.3 (218.5) 336.9
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 16.8 - - 9.0 25.8
Fixed Income Securities:
United States Government - 1,025.6 - - 1,025.6
Corporate Debt - 86.3 - - 86.3
State and Local Government - 114.3 - - 114.3
Subtotal Fixed Income Securities - 1,226.2 - - 1,226.2
Equity Securities - Domestic (b) 2,054.7 - - - 2,054.7
Total Spent Nuclear Fuel and Decommissioning Trusts 2,071.5 1,226.2 - 9.0 3,306.7
Other Investments (h) - - 31.8 - 31.8
Total Assets $ 2,308.3 $ 1,524.4 $ 288.1 $ (199.0) $ 3,921.8
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f) $ 0.9 $ 244.2 $ 167.2 $ (193.4) $ 218.9
Cash Flow Hedges:
Commodity Hedges (c) - 106.1 7.6 (28.5) 85.2
Interest Rate Hedges - 3.4 - - 3.4
Fair Value Hedges - 4.1 - - 4.1
Total Risk Management Liabilities $ 0.9 $ 357.8 $ 174.8 $ (221.9) $ 311.6

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AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 27.9 $ - $ - $ - $ 27.9
Risk Management Assets
Risk Management Commodity Contracts (c) - 1.1 - (1.1) -
Total Assets $ 27.9 $ 1.1 $ - $ (1.1) $ 27.9

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 28.7 $ - $ - $ - $ 28.7
Risk Management Assets
Risk Management Commodity Contracts (c) - 0.4 - (0.4) -
Total Assets $ 28.7 $ 0.4 $ - $ (0.4) $ 28.7


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APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 19.1 $ - $ - $ 19.1
Risk Management Assets
Risk Management Commodity Contracts (c) (g) - 27.0 37.3 (27.2) 37.1
Total Assets $ 19.1 $ 27.0 $ 37.3 $ (27.2) $ 56.2
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 32.5 $ 0.7 $ (31.8) $ 1.4

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Restricted Cash for Securitized Funding $ 16.9 $ - $ - $ - $ 16.9
Risk Management Assets
Risk Management Commodity Contracts (c) (g) - 19.4 19.9 (19.2) 20.1
Cash Flow Hedges:
Interest Rate Hedges - 2.4 - - 2.4
Total Risk Management Assets - 21.8 19.9 (19.2) 22.5
Total Assets $ 16.9 $ 21.8 $ 19.9 $ (19.2) $ 39.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 19.5 $ 0.6 $ (18.8) $ 1.3
Cash Flow Hedges:
Interest Rate Hedges - 3.4 - - 3.4
Total Risk Management Liabilities $ - $ 22.9 $ 0.6 $ (18.8) $ 4.7

205




I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 17.0 $ 8.9 $ (18.2) $ 7.7
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 28.0 - - 7.6 35.6
Fixed Income Securities:
United States Government - 1,155.8 - - 1,155.8
Corporate Debt - 87.3 - - 87.3
State and Local Government - 58.9 - - 58.9
Subtotal Fixed Income Securities - 1,302.0 - - 1,302.0
Equity Securities - Domestic (b) 2,274.8 - - - 2,274.8
Total Spent Nuclear Fuel and Decommissioning Trusts 2,302.8 1,302.0 - 7.6 3,612.4
Total Assets $ 2,302.8 $ 1,319.0 $ 8.9 $ (10.6) $ 3,620.1
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 21.9 $ 1.6 $ (22.4) $ 1.1

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 15.1 $ 2.5 $ (13.9) $ 3.7
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e) 16.8 - - 9.0 25.8
Fixed Income Securities:
United States Government - 1,025.6 - - 1,025.6
Corporate Debt - 86.3 - - 86.3
State and Local Government - 114.3 - - 114.3
Subtotal Fixed Income Securities - 1,226.2 - - 1,226.2
Equity Securities - Domestic (b) 2,054.7 - - - 2,054.7
Total Spent Nuclear Fuel and Decommissioning Trusts 2,071.5 1,226.2 - 9.0 3,306.7
Total Assets $ 2,071.5 $ 1,241.3 $ 2.5 $ (4.9) $ 3,310.4
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ 12.0 $ 0.4 $ (12.2) $ 0.2
206




OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.7 $ - $ (0.7) $ -
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 105.4 $ 0.1 $ 105.5

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.3 $ - $ (0.3) $ -
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 110.3 $ - $ 110.3

PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.4 $ 23.1 $ (0.5) $ 23.0
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 0.2 $ (0.1) $ 0.1

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.2 $ 10.3 $ (0.2) $ 10.3
207




SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2021
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.6 $ 15.0 $ (1.0) $ 14.6
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 0.4 $ (0.4) $ -

December 31, 2020
Level 1 Level 2 Level 3 Other Total
Assets: (in millions)
Risk Management Assets
Risk Management Commodity Contracts (c) (g) $ - $ 0.1 $ 3.3 $ (0.2) $ 3.2
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g) $ - $ - $ 1.7 $ - $ 1.7

(a)Amounts in 'Other'' column primarily represent cash deposits in bank accounts with financial institutions or third-parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)Amounts in 'Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for 'Derivatives and Hedging.''
(d)The June 30, 2021 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $2 million in periods 2022-2024; Level 2 matures $11 million in 2021, $37 million in periods 2022-2024, $22 million in periods 2025-2026 and $13 million in periods 2027-2033; Level 3 matures $96 million in 2021, $12 million in periods 2022-2024, $4 million in periods 2025-2026 and $(27) million in periods 2027-2033. Risk management commodity contracts are substantially comprised of power contracts.
(e)Amounts in 'Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(f)The December 31, 2020 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 2 matures $3 million in periods 2022-2024, $11 million in periods 2025-2026 and $1 million in periods 2027-2033; Level 3 matures $47 million in 2021, $37 million in periods 2022-2024, $14 million in periods 2025-2026 and $(13) million in periods 2027-2033. Risk management commodity contracts are substantially comprised of power contracts.
(g)Substantially comprised of power contracts for the Registrant Subsidiaries.
(h)See 'Warrants Held in Investee' section of Note 9 for additional information.
208




The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended June 30, 2021 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of March 31, 2021 $ 41.8 $ 6.6 $ 0.7 $ (104.0) $ 5.5 $ 0.5
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
18.6 6.2 0.4 1.7 4.8 3.1
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(10.6) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
15.4 - - - - -
Settlements (34.5) (13.0) (1.2) 0.6 (10.3) (4.5)
Transfers into Level 3 (d) (e) (0.8) - - - - -
Transfers out of Level 3 (e) (19.1) - - - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
90.4 36.8 7.4 (3.7) 22.9 15.5
Balance as of June 30, 2021 $ 101.2 $ 36.6 $ 7.3 $ (105.4) $ 22.9 $ 14.6
Three Months Ended June 30, 2020 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of March 31, 2020 $ 42.5 $ 6.6 $ 2.1 $ (120.9) $ 6.3 $ (2.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
39.1 23.5 2.8 - 3.9 0.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(17.2) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
22.0 - - - - -
Settlements (54.7) (28.9) (4.1) 2.6 (10.2) (2.4)
Transfers out of Level 3 (e) (0.2) - - - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
80.1 35.3 3.7 0.9 23.8 7.4
Balance as of June 30, 2020 $ 111.6 $ 36.5 $ 4.5 $ (117.4) $ 23.8 $ 3.3
Six Months Ended June 30, 2021 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2020 $ 113.3 $ 19.3 $ 2.1 $ (110.3) $ 10.3 $ 1.6
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
78.3 38.9 0.4 0.1 16.1 9.5
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(66.8) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
18.5 - - - - -
Settlements (110.6) (58.4) (2.6) 4.9 (26.4) (12.0)
Transfers into Level 3 (d) (e) (0.2) - - - - -
Transfers out of Level 3 (e) (25.6) - - - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
94.3 36.8 7.4 (0.1) 22.9 15.5
Balance as of June 30, 2021 $ 101.2 $ 36.6 $ 7.3 $ (105.4) $ 22.9 $ 14.6
209




Six Months Ended June 30, 2020 AEP APCo I&M OPCo PSO SWEPCo
(in millions)
Balance as of December 31, 2019 $ 109.9 $ 37.7 $ 5.8 $ (103.6) $ 15.8 $ 1.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
38.2 12.9 2.3 (0.9) 11.9 2.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)
(6.4) - - - - -
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c)
18.3 - - - - -
Settlements (113.7) (50.8) (8.1) 5.1 (27.6) (7.6)
Transfers into Level 3 (d) (e) (0.6) - - - - -
Transfers out of Level 3 (e) 4.3 0.7 0.4 - - -
Changes in Fair Value Allocated to Regulated Jurisdictions (f)
61.6 36.0 4.1 (18.0) 23.7 6.7
Balance as of June 30, 2020 $ 111.6 $ 36.5 $ 4.5 $ (117.4) $ 23.8 $ 3.3

(a)Included in revenues on the statements of income.
(b)Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)Included in cash flow hedges on the statements of comprehensive income.
(d)Represents existing assets or liabilities that were previously categorized as Level 2.
(e)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)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 assets/liabilities or accounts payable.

210




The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:

AEP
Significant Unobservable Inputs
June 30, 2021
Significant Input/Range
Fair Value Valuation Unobservable Weighted
Assets Liabilities Technique