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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 September 30, 20212022
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 |
| October 28, 202127, 2022 |
| |
American Electric Power Company, Inc. | 503,651,677513,863,678 | |
| ($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 |
September 30, 20212022 |
| | | | |
| | | | Page |
| | | | Number |
Glossary of Terms | |
| | | | |
Forward-Looking Information | |
| | | | |
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 | |
| Condensed Consolidated Financial Statements | |
| | | | |
AEP Texas Inc. and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
AEP Transmission Company, LLC and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
Appalachian Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
Indiana Michigan Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
Ohio Power Company and Subsidiaries: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
Public Service Company of Oklahoma: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Financial Statements | |
| | | | |
Southwestern Electric Power Company Consolidated: | |
| Management’s Narrative Discussion and Analysis of Results of Operations | |
| Condensed Consolidated Financial Statements | |
| | | | |
Index of Condensed Notes to Condensed Financial Statements of Registrants | |
| | | | |
Controls and Procedures | |
| | | | | | | | | | | | | | |
Part II. OTHER INFORMATION | |
| | | | |
| Item 1. | Legal Proceedings | |
| Item 1A. | Risk Factors | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | |
| Item 3. | Defaults Upon Senior Securities | |
| Item 4. | Mine Safety Disclosures | |
| Item 5. | Other Information | |
| Item 6. | Exhibits | |
| | | | |
SIGNATURE | | | |
| | | | |
| | | | |
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. EachExcept for American Electric Power Company, Inc., 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 Renewables | | A division of AEP Energy Supply, LLC that develops and/or acquires large scale renewable projects that are backed with long-term contracts with creditworthy counter parties. |
AEP System | | American Electric Power System, an electric system, owned and operated by AEP subsidiaries. |
AEP Texas | | AEP Texas Inc., an AEP electric utility subsidiary. |
AEP Transmission Holdco | | AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP. |
| | |
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. |
ALJ | | Administrative Law Judge. |
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. |
ATM | | At-the-Market. |
CAA | | Clean Air Act. |
| | |
CARES Act | | Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020. |
CCR | | Coal Combustion Residual. |
CLECO | | Central Louisiana Electric Company, a nonaffiliated utility company. |
CO2 | | Carbon dioxide and other greenhouse gases. |
Conesville PlantCO2e
| | A retired, single unit coal-fired generationCarbon dioxide equivalent. |
| | |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,296 MW nuclear plant totaling 651 MW located in Conesville, Ohio. The plant was jointly-ownedowned by AGR andI&M. |
COVID-19 | | Coronavirus 2019, a nonaffiliate.highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic. |
| | | | | | | | |
Term | | Meaning |
| | |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,288 MW nuclear plant owned by I&M. |
COVID-19 | | Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic. |
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, DCC Fuel XVI and DCC Fuel XVI,XVII, consolidated VIEs formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. |
Desert Sky | | Desert Sky Wind Farm LLC, a 170 MW wind electricity generation facility located on Indian Mesa in Pecos County, Texas in which AEP owns a 100% interest. |
DHLC | | Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. 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 ClauseClause. |
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. |
GHG | | Greenhouse gas. |
I&M | | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
IRA | | On August 16, 2022 President Biden signed into law legislation commonly referred to as the “Inflation Reduction Act” (IRA). |
IRS | | Internal Revenue Service. |
ITC | | Investment Tax Credit. |
IURC | | Indiana Utility Regulatory Commission. |
KGPCo | | Kingsport Power Company, an AEP electric utility subsidiary. |
KPCo | | Kentucky Power Company, an AEP electric utility subsidiary. |
| | |
KPSC | | Kentucky Public Service Commission. |
KTCo | | AEP Kentucky Transmission Company, Inc., a wholly-owned AEPTCo transmission subsidiary. |
KWh | | Kilowatt-hour. |
| | | | | | | | |
Term | | Meaning |
| | |
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. |
| | | | | | | | |
Term | | Meaning |
| | |
MISO | | Midcontinent Independent System Operator. |
Mitchell Plant | | A two unit, 1,560 MW coal-fired power plant located in Moundsville, West Virginia. The plant is jointly owned by KPCo and WPCo. |
MMBtu | | Million British Thermal Units. |
MPSC | | Michigan Public Service Commission. |
MTM | | Mark-to-Market. |
MW | | Megawatt. |
MWh | | Megawatt-hour. |
NAAQS | | National Ambient Air Quality Standards. |
Nonutility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries. |
NCWF | | North Central Wind Energy Facilities, a joint PSO and SWEPCo project, which includes three Oklahoma wind facilities totaling approximately 1,4851,484 MWs of wind generation. |
| | |
NOLC | | Net Operating Loss Carryforwards. |
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. |
ODFA | | Oklahoma Development Finance Authority. |
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.Credit. |
PUCO | | Public Utilities Commission of Ohio. |
PUCT | | Public Utility Commission of Texas. |
Racine | | A generation plant consisting of two hydroelectric generating units totaling 48 MWs located in Racine, Ohio and 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. |
| | | | | | | | |
Term | | Meaning |
| | |
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. |
| | | | | | | | |
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, a wholly-owned subsidiariessubsidiary of TCCAEP Texas 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 999998 MWs of wind generation in Oklahoma. |
Trent | | Trent Wind Farm LLC, a 156 MW wind electricity generation facility located between Abilene and Sweetwater in West Texas in which AEP owns a 100% interest. |
Turk Plant | | John W. Turk, Jr. Plant, a 650 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo. |
Utility Money Pool | | Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. |
| | | | | | | | |
Term | | Meaning |
| | |
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. |
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, costs of compliance with vaccination or testing mandatespotential government regulations and employees’ reactions to AEP,those regulations, electricity usage, employees including employee reactions to potential vaccination mandates,supply chain issues, customers, service providers, vendors and suppliers. |
• | The economic impact of escalating global trade tensions including the conflict between Russia and Ukraine, and the adoption or expansion of economic sanctions or trade restrictions. |
• | Inflationary or deflationary interest rate trends. |
• | Volatility 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 (i) if expected sources of capital, such as proceeds from the sale of assets or subsidiaries, do not materialize, and (ii) during periods when the time lag between incurring costs and recovery is long and the costs are material. |
• | Decreased demand for electricity. |
• | Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs. |
• | The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of storing and disposing of used fuel, including coal ash and SNF. |
• | The availability of fuel and necessary generation capacity and the performance of generation plants. |
• | The ability to recover fuel and other energy costs through regulated or competitive electric rates. |
• | The ability to transition from fossil generation and the ability to build or acquire renewable generation, transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms, including favorable tax treatment, and to recover those costs. |
• | New legislation, litigation 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 perceptionThe impact of thefederal tax legislation on results of operations, financial condition, cash flows or credit ratings. |
• | The risks associated with fuels used before, during and after the generation of electricity associated with the fuels used or the byproducts and wastes of such fuels, including coal ash and spent 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. |
| | | | | |
• | Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading market. |
• | Actions of rating agencies, including changes in the ratings of debt. |
• | The impact of volatility in the capital markets on the value of the investments held by the pension, OPEB, captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements. |
• | Accounting standards periodically issued by accounting standard-setting bodies. |
• | Other risks and unforeseen events, including wars and military conflicts, the effects of terrorism (including increased security costs), embargoes, naturally occurring and human-caused fires, cyber- securitycyber-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 20202021 Annual Report and in Part II of this report.
The CompanyRegistrants may use itsAEP’s website as a distribution channel for material company information. Financial and other important information regarding the CompanyRegistrants is routinely posted on and accessible through the Company’sAEP’s website at www.aep.com/investors/. In addition, you may automatically receive email alerts and other information about the CompanyRegistrants when you enroll your email address by visiting the “Email Alerts” section at www.aep.com/investors/.
Company Website and Availability of SEC Filings
Our principal corporate website address is www.aep.com. Information on our website is not incorporated by reference herein and is not part of this Form 10-Q. We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding AEP.
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 September 30, 2021, an estimated $67 million of capital expenditures and $149 million of restoration expenses have been incurred related to the severe winter weather. Approximately $142 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 is expected to seek recovery in separate filings.In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC.As part of the filing, SWEPCo requested recovery of the carrying charges on the regulatory asset at a weighted average cost of capital through a rider beginning in January 2022.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 September 30, 2021, PSO and SWEPCo have deferred regulatory assets of $673 million and $433 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 $107 million, $151 million and $175 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. SWEPCo is recovering these fuel costs at an interim carrying charge of 0.8%. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing
securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. 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 is recovering these fuel costs at an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma to permit securitization of 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. The application requests an order on the prudency of the extraordinary fuel and purchase of electricity costs and a carrying charge of the commission authorized weighted average cost of capital until securitization bonds can be issued. In October 2021, OCC staff and intervenors filed testimony supporting securitization of these costs and a carrying charge until costs are securitized ranging from the interim rate of 0.75% to the actual cost of capital used to finance the costs of 2.32%. In addition, OCC staff supported the prudency of PSO's requested costs while one intervenor recommended disallowances of up to $40 million. A procedural schedule has been set with an ALJ report to be filed in January 2022. An order from the OCC is expected in the first quarter of 2022.
In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application supported a five-year recovery at a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.082% to 1.625%. A hearing with the PUCT is scheduled for November 2021.
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 September 30, 2021, $56 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 nine months ended September 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 September 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of residential customers in Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices once available relief funds are received from the state.
AEP has been and continues to be proactive in engaging with customers to collect payments or establish payment arrangements for outstanding balances. As of September 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 September 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 began transitioning On-Site employees back to their AEP workplace and Hybrid employees with set schedules back to their AEP workplace in October 2021. Remote employees are scheduled to begin transitioning back to their AEP workplace in November 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, increased demand due to the economic recovery from the pandemic, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services. 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 third quarter of 20212022 increased by 3%2.6% from the third quarter of 2020.2021. Weather-normalized residential sales decreased by 1.6%0.8% in the third quarter of 20212022 from the third quarter of 2020.2021. AEP’s third quarter 20212022 industrial sales volumes increased by 7%6.0% compared to the third quarter of 2020.2021. The increase in industrial sales was spread across many industries. Weather-normalized commercial sales increased 5%3.4% in the third quarter of 20212022 from the third quarter of 2020.2021. The increase in commercial sales was spread across many sectors.
AEP’s weather-normalized retail sales volumes for the nine months ended September 30, 20212022 increased by 2.3%3.1% compared to the nine months ended September 30, 2020.2021. Weather-normalized residential sales decreasedincreased by 0.9%0.3% for the nine months ended September 30, 20212022 compared to the nine months ended September 30, 2020.2021. AEP’s industrial sales volumes for the nine months ended September 30, 20212022 increased 4.2%by 5.5% compared to the nine months ended September 30, 2020.2021. The recoveryincrease in industrial sales volumes was spread across many industries. Weather-normalized commercial sales increased 4.3%3.8% for the nine months ended September 30, 20212022 compared to the nine months ended September 30, 2020.2021. The increase in commercial sales was spread across many sectors.
Supply Chain Disruption and Inflation
The current year increase in industrial and commercial sales volumes is primarilyRegistrants have experienced certain supply chain disruptions driven by aseveral factors including staffing and travel issues caused by the COVID-19 pandemic, international tensions including the ramifications of regional conflict, increased demand due to the economic recovery from the COVID-19 pandemic. In 2020, public health restrictions significantly disruptedpandemic, inflation, labor shortages in certain trades and shortages in the availability of certain raw materials. These supply chain disruptions have not had a material impact on the Registrants net income, cash flows and financial condition, but have extended lead times for certain goods and services and have contributed to higher prices for fuel, materials, labor, equipment and other needed commodities. Management has implemented risk mitigation strategies in an attempt to mitigate the impacts of these supply chain disruptions. The United States economy has encountered a significant level of inflation that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and industrialat what rate. A prolonged continuation or a further increase in the severity of supply chain and commercial demand for energyinflationary disruptions could result in AEP’s service territory. Similarly,additional increases in the current year decline in weather-normalized residential sales volumes is driven by the cessationcost of stay at home restrictions that were in place in 2020certain goods and the gradual returnservices and further extend lead times which could reduce future net income and cash flows and impact financial condition.
Strategic Evaluation of customers to the workplace.AEP Energy
AEP revisedhas initiated a strategic evaluation for its forecast for 2021 weather-normalizedownership in AEP Energy, a wholly-owned retail sales volumesenergy supplier that supplies electricity and/or natural gas to residential, commercial and industrial customers. AEP Energy provides various energy solutions in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C. AEP Energy had approximately 672,000 customer accounts as of September 2021 from30, 2022. Potential alternatives may include, but are not limited to, continued ownership or a sale of all or a part of AEP Energy. Management has not made a decision regarding the forecast presentedpotential alternatives, but expects to complete the strategic evaluation in the 2020 10-K. In 2021, AEP currently anticipates weather-normalized retail sales volumes will increase by 2.2%. AEP expects industrial class sales volumes to increase by 4.3% in 2021, while weather-normalized residential sales volumes are projected to decrease by 0.9%. Finally, AEP currently projects weather-normalized commercial sales volumes to increase by 3.7%.first half of 2023.
Federal Tax Legislation
(a)Percentage change forOn August 16, 2022, President Biden signed H.R. 5376 into law, commonly known as the year ended December 31, 2020 as compared to the year ended December 31, 2019.Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted
financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third parties for cash. With the exception of PTCs and ITCs, this legislation is prospective and has no material impact on the current period financial statements. As presentedsignificant guidance from Treasury and the IRS is expected on the tax provisions in the 2020IRA, AEP 10-K: Forecasted percentage change forwill continue to monitor any issued guidance and evaluate the year ending December 31, 2021 compared to the year ended December 31, 2020.impact on future net income, cash flows and financial condition.
(c)
Revised in September 2021: Forecasted percentage change for the year ending December 31, 2021 compared to the year ended December 31, 2020.
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 atAugust 2022, the Virginia Supreme Court issued its opinion on submitted appeals of APCo’s 2017-2019 Virginia Triennial Review concluding that the Virginia SCC: a) erred in finding it was not reasonable for APCo to record all remaining costs associated with early retirement of certain coal-fired generating plants in the 2017-2019 earnings test period, b) did not err by ordering APCo to retroactively implement depreciation rates for the years 2018 and 2019 and c) did not err in finding that APCo’s affiliate costs from OVEC were reasonable. The Virginia Supreme Court then remanded the issue regarding the retired coal-fired plants back to 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.proceedings.
In MarchSeptember 2022, and in response to the Virginia Supreme Court opinion and subsequent Virginia SCC order initiating a remand proceeding, APCo submitted to the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation resulting in a proposed $37 million regulatory asset related to previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band, (b) an updated requested annual base rate increase of $41 million effective October 2022 and (c) a requested rider to recover, over the period October 2022 through January 2024, approximately $72 million related to an APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s requested $41 million annual base rate increase includes approximately $12 million related to the recovery of APCo’s regulatory asset for previously incurred costs as a result of earning below its 2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate increases effective October 2022, both of which are subject to refund and review by the Virginia SCC. An order from the Virginia SCC issued an order confirming certainin the remand proceeding is expected in the fourth quarter 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. 2022.
In September 2021,2022, APCo submitted its brief beforeexpensed the Virginia Supreme Court.The briefremaining $25 million closed coal plant regulatory asset that was in alignment with the assignments of error filedpreviously ordered by APCo in March 2021. In October 2021, the Virginia SCC and certain intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignmentsrecorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of error inearning below its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with an intervenor’ s assignments of error in a separate appeal of the same decision.
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 byOctober 2022 through January 2024 net income, cash flows and financial condition is expected to be positively impacted pending the Virginia Supreme Court, it could initially reduce future net incomeSCC’s order on APCo’s requested base rate 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.rider rate increases.
•2020 Ohio Base Rate Case2020-2022 Virginia Triennial Review - In June 2020, OPCo filedMarch 2023, APCo will submit its required Virginia earnings test calculation for the 2020-2022 Triennial Review period. For Triennial Review periods in which a request withVirginia utility earns below its authorized ROE band, 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,utility may file to recover expenses incurred, up to 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 continuationbottom of the DIR with annual revenue capsauthorized ROE band, related to major storms, the early retirement 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 PUCOfossil fuel generating
in May 2021assets and initial briefs were filed in June 2021 followed by reply briefs in July 2021. An order from the PUCO is expected in the fourth quarter of 2021.
•Hurricane Laura - In August 2020, Hurricane Laura hit the coasts of Louisianacertain projects necessary to comply with state 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.federal environmental legislation. As of September 30, 2021, management estimates that SWEPCo2022, APCo has deferred approximately $25 million related to previously incurred incremental other operation and maintenance expenses of $92 million ($89 million of which has been deferredcosts as a regulatory asset related toresult of the Louisiana jurisdiction)current estimate that APCo will earn below the bottom of its authorized ROE band during the 2020-2022 Triennial Review period. If it is determined that APCo has earned above the bottom of its authorized ROE band for the 2020-2022 Triennial Review period it could reduce future net income and incremental capital expenditures of $18 million, all of which is related to the Louisiana jurisdiction. In October 2021, SWEPCo requested recovery of these storm costs, in addition to SWEPCo’s various other storm costs, in a filing with the LPSC.cash flows and impact financial conditions.
•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. Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals. In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court.
In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgementjudgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decisiondecision. SWEPCo and expects to submit a Petitionthe PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. SWEPCo plans to file a request for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.
IfManagement does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of September 30, 2022. However, if SWEPCo is ultimately unable to recover capitalized Turk Plant costs including AFUDC in excess of the Texas jurisdictional capital cost cap it would be expected to result in a pretax net disallowance ranging from $80 million to $100$90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $160$180 million related to revenues collected from February 2013 through September 20212022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.
•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 currentterminated energy efficiency programs as of December 31, 2020, including OPCo’s shared savings revenues of $26 million annually and phased out renewable mandates after 2026. HB 6 also provided for thecontinued recovery of existing renewable energy contracts on a bypassable basis through 2032 and included a provision for continued recovery of OVEC costs through 2030 which will beis allocated to all electric distribution utilitiesutility customers in Ohio on a non-bypassable basis. OPCo’s Inter-Company Power Agreement for OVEC terminates in June 2040. In July 2020, an investigation led by the U.S. Attorney’s Office resulted in a federal grand jury indictment of the Speaker of the Ohio House of Representatives, Larry Householder, four other individuals, and Generation Now, an entity registered as a 501(c)(4) social welfare organization, in connection with an alleged racketeering conspiracy involving the adoption of HB 6. Certain defendants in that case have since pleaded guilty. In August 2020, an2021, four AEP shareholders filed derivative actions purporting to
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, which was fully briefed on July 26, 2021. Oral arguments on the motion to dismiss is scheduled for November 23, 2021. In addition, four AEP shareholders have filed derivative actions purporting to assert claims on behalf of AEP against certain AEP officers and directors, all of which are currently stayed.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, rescindedrepealed 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 daysin May 2021 and leaves unchanged other provisions of HB 6 regarding energy efficiency programs, recovery of renewable energy costs and recovery of OVEC costs. To the extent that the law changes or OPCo is unable to recover the costs of renewable energy contracts on a bypassable basis by the end of 2032, recover costs of OVEC after 2030 or incurs significant costs associated with the 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 requested 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 proposed 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%).
In June 2021, the WVPSC issued an order approving the investment tracker mechanism with an initial annual revenue requirement of $44 million ($36 million related to APCo) effective September 2021 based on a 9.25% ROE. 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. Under the conditions of the order and with certain exceptions as outlined by the WVPSC, APCo and WPCo are prohibited from filing a base rate case before June 30, 2024.
•In April 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify its incentive for transmission owners that join RTOs (RTO Incentive). Under the supplemental NOPR, the RTO Incentive would be modified such that a utility would only be eligible for the RTO Incentive for the first three years after the utility joins a FERC-approved Transmission Organization. This is a significant departure from a previous NOPR issued in 2020 seeking to increase the RTO Incentive from 50 basis points to 100 basis points. The supplemental NOPR also required utilities that have received the RTO Incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff prospectively. The supplemental NOPR was subject to a 60 day comment period followed by a 30 day period for reply comments. In July 2021, AEP submitted reply comments. AAEP is awaiting a final rule from the FERC.
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 behave an adverse impact on AEP’s Ohio transmission owning subsidiaries. In its February 2022 order on rehearing, the FERC affirmed the decision in its July 2021 order. The case is currently pending appeal at the United States Court of Appeals for the Sixth Circuit. In May 2022, the United States Court of Appeals for the Sixth Circuit issued an order to hold the appeal in abeyance pending resolution of FERC proceedings on the fourth quarterOffice of 2021.the Ohio Consumers’ Counsel’s February 2022 RTO Incentive Complaint.
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.
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.
•FERC RTO Incentive Complaint - In February 2022, the Office of the Ohio Consumers’ Counsel filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the Ohio Consumers’ Counsel’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. Management believes its financial statements adequately address the impact of the February 2022 complaint. If the
FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
•2021 Louisiana Storm Cost Filing - In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization of the deferred storm costs as the LPSC staff had recommended in their testimony. An order is expected before the end of 2022. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
•In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history.The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. As a result of the severe winter weather, PSO and SWEPCo incurred approximately $1.1 billion of extraordinary fuel costs and purchases of electricity, which were deferred as regulatory assets.
In April 2021, the OCC approved the deferral of PSO’s extraordinary fuel costs and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma permitting securitized financing of qualified costs from extreme weather events. This legislation provides certain authority to the OCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by the ODFA, an Oklahoma governmental agency. In January 2022, PSO, OCC staff and certain intervenors filed a joint stipulation and settlement agreement with the OCC to approve the securitization of PSO’s extraordinary fuel costs and purchases of electricity. In February 2022, the OCC approved the joint stipulation and settlement agreement which included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.
In September 2022, PSO received proceeds of $687 million from the ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will serve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to the ODFA. The securitization charges billed to and collected from customers are not included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.
In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.
In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.
As of September 30, 2022, SWEPCo had regulatory assets of $349 million relating to natural gas expenses and purchases of electricity incurred during the February 2021 severe winter weather event. SWEPCo’s deferred regulatory asset consists of $85 million, $126 million and $138 million related to the Arkansas, Louisiana and Texas jurisdictions, respectively.
If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.
•AEP transitioned to stand-alone treatment of NOLC in its PJM and SPP transmission formula rates beginning with 2022 projected transmission revenue requirements and 2021 true-up to actual transmission revenue requirements, and provided notice of this change in informational filings made with the FERC. Stand-alone treatment of the NOLCs for transmission formula rates increased the 2021 and 2022 annual revenue requirements by $78 million and $60 million, respectively. Through the third quarter of 2022, the Registrants’ financial statements reflect a provision for refund for all NOLC revenues billed by PJM and SPP. Also, the impact of inclusion of the NOLC in the 2021 annual formula rate true-up not yet billed by PJM and SPP is not reflected in the Registrants’ revenues and expenses as the Registrants have not met the requirements of alternative revenue recognition in accordance with the accounting guidance for “Regulated Operations”.
AEP is also transitioning to stand-alone treatment of NOLC in retail jurisdiction base rate case filings. As a result of retail jurisdiction base rate cases in Arkansas, Indiana, Oklahoma and Texas, inclusion of NOLCs in rates in those jurisdictions is contingent upon a supportive private letter ruling from the IRS.
•SPP Capacity Planning Reserve Margin - In July 2022, SPP approved a plan to increase its capacity planning reserve margin from 12% to 15% starting in the summer of 2023. Compliance filings are due to SPP in February 2023 and any deficiencies are required to be remedied by May 2023. SPP’s annual non-compliance charge as a result of not meeting capacity requirements could range from approximately $86 thousand per MW to approximately $171 thousand per MW. Non-compliance could also result in a failure to meet NERC criteria and violating SPP’s tariff before FERC. As of September 30, 2022, the increase in the capacity planning reserve margin for PSO and SWEPCo to comply with this new SPP requirement is approximately 265 MWs. Management is currently evaluating options and expects to comply with SPP’s 2023 capacity planning reserve margin requirements. If PSO or SWEPCo incur charges or are unable to recover, or experience delays in recovering, the costs of complying with SPP’s rule, it could reduce future net income and cash flows and impact financial condition.
Utility Rates and Rate Proceedings
The Registrants file rate cases with their regulatory commissions in order to establish fair and appropriate electric service rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Registrants’ completed and pending base rate case proceedings in 2021.2022. See Note 4 - Rate Matters for additional information.
Completed Base Rate Case Proceedings
| | | Approved Revenue | | Approved | | New Rates | | Approved Revenue | | Approved | | New Rates |
Company | Company | | Jurisdiction | | Requirement Increase | | ROE | | Effective | Company | | Jurisdiction | | Requirement Increase | | ROE | | Effective |
| | | | | (in millions) | | | | | | | | | (in millions) | | | | |
KPCo | | Kentucky | | $ | 52.7 | | (a) | | 9.3% | | January 2021 | |
| SWEPCo | | SWEPCo | | Texas | | $ | 39.4 | | | 9.25% | | March 2021 |
I&M | | I&M | | Indiana | | 61.4 | | (a) | | 9.7% | | February 2022 |
SWEPCo | | SWEPCo | | Arkansas | | 48.7 | | | 9.5% | | July 2022 |
KGPCo | | KGPCo | | Tennessee | | 5.8 | | | 9.5% | | August 2022 |
(a)See “2020 Kentucky“2021 Indiana Base Rate Case” sectionCase “Section of Note 4 - Rate Matters in the 20202021 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) | | | | | |
SWEPCo | | Louisiana | | December 2020 | | $ | 94.7 | | | 10.35% | | 9.1%-9.8% | |
Deferred Fuel Costs
Increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has led to an increase in the under collection of fuel costs from customers in most jurisdictions. The table below illustrates the increase (decrease) in the deferred fuel regulatory assets by company and jurisdiction, excluding the impacts of the February 2021 severe winter weather event. See the “February 2021 Severe Winter Weather Impacts in SPP” sections in Note 4 for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Traditional FAC | | As of | | As of | | Increase/ |
Company | | Jurisdiction | | Recovery Reset | | September 30, 2022 | | December 31, 2021 | | (Decrease) |
APCo | | Virginia (a) | | Annually | | $ | 359.5 | | | $ | 128.6 | | | $ | 230.9 | |
APCo | | West Virginia | | Annually | | 235.2 | | | 72.7 | | | 162.5 | |
I&M | | Indiana | | Bi-Annually | | 19.2 | | | — | | | 19.2 | |
I&M | | Michigan | | Annually | | 6.2 | | | 6.4 | | | (0.2) | |
PSO | | Oklahoma (b) | | Annually | | 419.9 | | | 194.6 | | | 225.3 | |
SWEPCo | | Arkansas | | Annually | | 67.7 | | | 23.1 | | | 44.6 | |
SWEPCo | | Louisiana | | Monthly | | 2.4 | | | 11.1 | | | (8.7) | |
SWEPCo | | Texas | | Tri-Annually | | 165.9 | | | 47.0 | | | 118.9 | |
KPCo | | Kentucky | | Monthly | | 24.4 | | | 8.2 | | | 16.2 | |
WPCo | | West Virginia | | Annually | | 195.2 | | | 101.6 | | | 93.6 | |
| | | | Total (c) | | $ | 1,495.6 | | | $ | 593.3 | | | $ | 902.3 | |
(a)Includes $191 million of noncurrent deferred fuel classified as a Regulatory Asset on APCo’s balance sheets as of September 30, 2022.
(b)Includes $241 million of noncurrent deferred fuel classified as a Regulatory Asset on PSO’s balance sheets as of September 30, 2022.
(c)Includes $24 million and $8 million as of September 30, 2022 and December 31, 2021, respectively, of deferred fuel classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
The AEP utility subsidiaries are working with various state commissions on the timing of recovering deferred fuel balances and have made the following recent filings:
In April 2022, APCo and WPCo submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, effective September 1, 2022. The WVPSC requested West Virginia staff perform a prudency review of APCo and WPCo’s actual and forecasted ENEC costs. Management expects to receive a WVPSC order on the 2022 ENEC filing in the fourth quarter of 2022 and a separate WVPSC order on the prudency review of the ENEC costs in the first quarter of 2023. See “2021 and 2022 ENEC Filings” section of Note 4 for additional information.
In August 2022, PSO requested an interim update to its annual Fuel Cost Adjustment (FCA) rates in accordance with the terms of the established tariff which allows PSO or the OCC staff to request an interim FCA adjustment in the event that the annual FCA over/under-recovered balance is $50 million or more on a cumulative basis. In September 2022, the Director of the Public Utility Division of the OCC approved a FCA rate designed to collect a $402 million deferred fuel balance over a 27 month period, effective with the first billing cycle of October 2022. PSO’s fuel and purchased power expenses are subject to an annual prudency review by the OCC.
In September 2022, APCo submitted a request to the Virginia SCC to increase its annual fuel factor by approximately $279 million. APCo will implement interim FAC rates effective November 2022 subject to Virginia SCC review. To help mitigate the impact of rising fuel costs on customer bills, APCo proposed to recover its
Pending Basedeferred fuel balance as of October 31, 2022 over two years. An order from the Virginia SCC is expected in the first quarter of 2023.
In September 2022, SWEPCo filed a request with the APSC for an interim increase to its current Energy Cost Rate Case Proceedings(ECR) to recover $44 million of additional fuel costs incurred from April 2022 through August 2022, subsequent to the last annual ECR rate change. The interim rate will be effective with the first billing cycle of October 2022 and will be in effect for six months until the ECR is reset in April 2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 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 | | 100.4 | | (b) | | 10.35% | | 9%-9.22% | (c) |
SWEPCo | | Louisiana | | December 2020 | | 94.7 | | | | 10.35% | | 9.1%-9.8% | (d) |
PSO | | Oklahoma | | April 2021 | | 127.5 | | | | 10% | | 9%-9.4% | (e) |
I&M | | Indiana | | July 2021 | | 104.0 | | (f) | | 10% | | 9.1%-9.3% | (g) |
SWEPCo | | Arkansas | | July 2021 | | 85.0 | | | | 10.35% | | (h) | |
Dolet Hills Power Station and Related Fuel Operations
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. In April 2020, SWEPCo and CLECO jointly filed a notification letter to the LPSC providing notice of the cessation of lignite mining. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.
The remaining book value of Dolet Hills Power Station non-fuel related assets are recoverable by SWEPCo through a combination of base rates and rate riders. As of September 30, 2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station was $113 million, including materials and supplies, net of cost of removal collected in rates.
Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses and are subject to prudency determinations by the various commissions. After closure of the DHLC mining operations and the Dolet Hills Power Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in existing fuel clauses. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.
In March 2021, the LPSC issued an order allowing SWEPCo to recover up to $20 million of fuel costs in 2021 and defer approximately $30 million of additional costs with a recovery period to be determined at a later date. In August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $30 million deferral, with refunds to customers over five years. In September 2022, SWEPCO filed rebuttal testimony addressing the LPSC staff recommendations.
In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.
(a)In March, 2021August 2022, SWEPCo filed a joint stipulation and settlement agreement was filedfuel reconciliation with the PUCO which included a $68 million decrease in base rates based upon a ROEPUCT covering the fuel period of 9.7%.
(b)January 1, 2020 through December 31, 2021. 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 $85 million primarily due to increased investments.
(c)An ALJ proposed a base rate increase of $41 million based upon a ROE of 9.45%.
(d)LPSC staff recommended a base rate increase of $6 million.
(e)In September 2021, a contested joint stipulation and settlement agreement was filed with the OCC which included a $51 million increase in base rates based upon a ROE of 9.4%.
(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)Intervenors proposed a decrease in base rates ranging from $13 million to $68 million.
(h)Intervenor testimony is expected in December 2021.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Pirkey Plant and Related Fuel Operations
In 2020, management announced plans to retire the Pirkey Plant in 2023. The Pirkey Plant non-fuel costs are recoverable by SWEPCo through base rates and fuel costs are recovered through active fuel clauses and are subject to prudency determinations by the various commissions. As of September 30, 2022, SWEPCo’s share of the net investment in the Pirkey Plant was $216 million, including CWIP, before cost of removal. Sabine is a mining operator providing mining services to the Pirkey Plant. Under the provisions of the mining agreement, SWEPCo is required to pay, as part of the cost of lignite delivered, an 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 $49 million as of September 30, 2022. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event. Upon cessation of lignite deliveries by Sabine to the Pirkey Plant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in existing fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Renewable Generation
The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide clean energy options to customers that meet both their energy and capacity needs.
Contracted Renewable Generation Facilities
In recent years, AEP continues to develophas developed its renewable portfolio within the Generation & Marketing segment. Activities includeOther activities have included, but are not limited to, 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 developsdeveloped and/or acquiresacquired large scale renewable generation projects that are backed with long-term contracts with creditworthy counterparties.
In February 2022, AEP management announced the initiation of a process to sell all or a portion of AEP Renewables’ competitive contracted renewables portfolio within the Generation & Marketing segment. Subsequently, AEP’s investment in Flat Ridge 2 Wind LLC was removed from the competitive contracted renewables sale portfolio. In June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries in AEP’s Statement of Income. In the third quarter of 2022, AEP recorded an additional $2 million pretax other than temporary impairment charge. The carrying value of AEP’s investment in Flat Ridge 2 was not material to AEP as of September 30, 2022. In September 2022, AEP signed a Purchase and Sale Agreement with a nonaffiliate for AEP’s interest in Flat Ridge 2, subject to FERC approval. Management expects the transaction to close in the fourth quarter of 2022 and have an immaterial impact on the financial statements. See “Impairments” section of Note 6 for additional information.
As of September 30, 2021, subsidiaries within AEP’s Generation & Marketing segment had approximately 1,633 MWs of2022, excluding Flat Ridge 2, the competitive contracted renewable portfolio assets totaled 1.4 gigawatts of generation projects in-service. In addition,resources representing consolidated solar and wind assets, with a net book value of $1.2 billion, and a 50% interest in five joint venture wind farms, totaling $246 million, accounted for as equity method investments. The anticipated disposition of all or a portion of the AEP Renewables’ portfolio has not met the accounting requirements to be presented as Held for Sale as of September 30, 2021,2022. If AEP is unable to recover the book value or carrying value of these subsidiaries had approximately 155 MWs of renewable generation projects under construction with total estimated capital costs of $221 million related to these projects.assets through a sales process, it could reduce future net income and impact financial condition.
Regulated Renewable Generation Facilities
North Central Wind Facilities
In 2020, PSO received approval from the OCC and SWEPCo received approval from the APSC and LPSCregulatory approvals to acquire the NCWF, comprised of three Oklahoma wind facilities totaling 1,4851,484 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 undivided interests of 45.5% and 54.5% of the project,NCWF, respectively. Output from the NCWF serves retail load in PSO’s Oklahoma service territory and both retail and FERC wholesale load in SWEPCo’s service territories in Arkansas and Louisiana. The Oklahoma and Louisiana portions of the NCWF revenue requirement, net of PTC benefit, are recoverable through authorized riders beginning at commercial operation and until such time as amounts are reflected in base rates. The Arkansas portion of the NCWF revenue requirement was approved for recovery through base rates in the 2021 Arkansas Base Rate Case. The table below provides a summary of the facilities as of September 30, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Project | | In-Service Date | | Net Book Value | | Federal PTC Qualification % (a) | | Generating Capacity |
| | | | (in millions) | | | | (in MWs) |
Sundance | | April 2021 | | $ | 282.3 | | | 100 | % | | 199 | |
Maverick | | September 2021 | | 398.3 | | | 80 | % | | 287 | |
Traverse | | March 2022 | | 1,255.0 | | | 100 | % | (b) | 998 | |
(a)PTC benefits are available for a ten year period following the in-service date.
(b)The PTC for Traverse was increased to 100% in the third quarter of 2022 as a result of the IRA legislation.
See “North Central Wind Energy Facilities” section of Note 6 for additional information.
Recent Renewable Generation Filings
In December 2021 and January 2022, APCo filed petitions with the Virginia SCC and WVPSC, respectively, for prudency and cost recovery of: (a) an APCo-owned 204 MW wind generation facility, (b) three APCo-owned solar generation facilities totaling 205 MWs and (c) three solar purchased power agreements (PPAs) totaling 89 MWs. In June 2022, the WVPSC approved APCo’s January 2022 petition for cost recovery of an APCo-owned 50 MW solar generation facility which was included within the 205 MWs requested. In July 2022, the Virginia SCC approved APCo’s December 2021 petition for prudency and cost recovery as submitted. An order from the WVPSC is anticipated in the fourth quarter of 2022 related to the remaining items in APCo’s January 2022 petition. In September 2022, APCo received a notice of termination for a 19 MW Solar PPA due to the developer being unsuccessful in obtaining local permits. The 19 MW Solar PPA was included in the December 2021 and January 2022 petitions filed with the Virginia SCC and WVPSC, respectively. If the WVPSC does not approve one or more of the projects included in APCo’s January 2022 petition, the associated allocation of cost and production of the facilities will be assigned to Virginia retail customers. Under separate, existing APCo Virginia and West Virginia tariffs, APCo is also authorized for cost recovery of an additional 40 MWs of recently completed solar PPAs.
In May 2022, SWEPCo submitted filings before the APSC, LPSC and PUCT requesting approval to acquire three renewable energy projects totaling 999 MWs. In October 2022, SWEPCo also submitted the necessary filings with the FERC. The projects are comprised of two wind facilities, totaling 799 MWs, and one solar facility, totaling 200 MWs. One of the wind facilities, totaling approximately $2 billion.201 MWs, is expected to reach commercial operation in December 2024 with the remaining facilities expected to reach commercial operation in December 2025.
In June 2021, the IRS issued a notice extending the “Continuity Safe Harbor” deadlinesSignificant Renewable Generation Requests 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.Proposal (RFP)
In April 2021, PSOAs part of AEP’s transition to diversify the company’s generation resources and SWEPCo acquired respective undivided ownership interestsbuild its renewable generation portfolio, the Registrants file RFPs 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 proportionan effort to their undivided ownership interests. Sundance was placed in-service in April 2021. In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021. As of September 30, 2021, PSO and SWEPCo had approximately $314 million and $376 million, of Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. The Traverse wind facility is targeted to be acquired and placed in-service between January 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. Theidentify potential wind and solar generationprojects. The table below includes the significant RFPs recently issued. These projects would be subject to regulatory approval.
In September 2021, PSO issued draft requests | | | | | | | | | | | | | | | | | | | | | | | | | | |
Company | | Issuance Date | | Generation Type | | Owned/ PPA | | Generating Capacity |
| | | | | | | | (in MWs) |
APCo | | January 2022 | | Wind | | Owned | | 1,000 | |
APCo | | January 2022 | | Solar (a) | | Owned | | 100 | |
APCo | | February 2022 | | Solar | | Owned | | 150 | |
APCo | | June 2022 | | Solar/Wind | | PPA | | 100 | |
I&M | | March 2022 | | Wind | | Owned | | 800 | |
I&M | | March 2022 | | Solar (a) | | Owned | | 500 | |
PSO | | November 2021 | | Wind | | Owned | | 2,800 | |
PSO | | November 2021 | | Solar (a) | | Owned | | 1,350 | |
SWEPCo | | September 2022 | | Wind | | Owned | | 1,900 | |
SWEPCo | | September 2022 | | Solar (a) | | Owned | | 500 | |
Total Significant RFP’s | | | | | | | | 9,200 | |
(a)Includes an option for proposals to acquire up to 2,600 MWs of wind and 1,350 MWs of solar generation resources. The wind and solar generation projects would be subject to regulatory approval.battery storage.
Disposition of KPCo and AEP Kentucky Transmission Company, Inc. (KTCo)KTCo
In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Oakville, Ontario, Canada based Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. The sale isIn May 2022, the KPSC approved the transfer of KPCo to Liberty subject to regulatory approvals fromcertain conditions contingent upon the FERC,closing of the KPSC,sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and clearance from the Committee on Foreign Investment in the United States. The sale remains subject to FERC approval under Section 203 of the Federal Power Act.
KPCo currently operatesIn September 2022, AEP, AEPTCo and owns a 50% interest inLiberty entered into an amendment (Amendment) to the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) withSPA which reduced the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingentpurchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval byof the KPSC, WVPSC and FERCsale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo. The Amendment also provided that the closing shall not occur prior to January 4, 2023, unless mutually agreed to by AEP and Liberty.
Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement
KPCo and WPCo pursuant to which WPCo will replace KPCo aseach own a 50% undivided interest in the operator1,560 MW coal-fired Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and KPCo employees atinventory, was $576 million.
In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing AEP’s filings in May 2022 and July 2022. Those orders proposed materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will become employeescontinue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each
state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of WPCo atMitchell Plant.
Transfer of Ownership
FERC Proceedings
In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the FERC issued an order formally notifying AEP that it was exercising its ability to take up to an additional 180 days to act on the application. An order from the FERC is expected in the fourth quarter of 2022.
KPSC Proceedings
In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the transaction. Undersale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%. As a result of the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interestconditions imposed by KPSC, in the Mitchell Plantsecond quarter of 2022, AEP recorded a $69 million loss on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retireexpected sale of the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase priceKentucky Operations in accordance with accounting guidance for KPCo’s 50% ownership interest in the Mitchell Plant will be determined through the mutual agreement of WPCo and KPCo (subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals if KPCo and WPCo are unable to reach agreement as to the purchase price.Fair Value Measurement.
TheFurther, as a result of the Amendment and the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement. AEP recorded a $263 million pretax loss ($218 million net of tax) on the expected sale of the Kentucky Operations for the nine months ended September 30, 2022. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion.
Subject to receipt of FERC authorization under Section 203 of the Federal Power Act, the sale is expected to close in the second quarter of 2022January 2023 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction.
AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.
AEP expects to receive approximately $1.45 billion in cash, net of taxes and transaction fees. AEP plans to use the proceeds to eliminate forecasted equity needs in 2022 as the company invests in regulated renewables, transmission and other projects. AEP expects the sale to have a one-time, immaterial impact on after-tax earnings.
Racine
In February 2021, AEP signed an agreement to sell Racine to a nonaffiliated party. As of September 30, 2021, the net book value of Racine was $45 million. The sale of Racine was approved by the U.S. Army Corps of Engineers in the third quarter of 2021. The sale also requires approval from the FERC. The sale is expected to close in the fourth 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 ceased in October 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. As of September 30, 2021, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $146 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 $44 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 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.
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. As of September 30, 2021, SWEPCo’s share of the net investment in the Pirkey Power Plant is $203 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 $108 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 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 suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. See “Obligations under the New Source Review Litigation Consent Decree” section below for additional information.
After the litigation proceeded at the District Courtdistrict court and Circuit Court levels, onappellate court, in April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5$116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. 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. 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 required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. Management believes its financial statements appropriately reflect the resolution of the litigation.
Upon the end of the Rockport Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Unit 2 will be billed 100% to I&M under a FERC-approved unit power agreement. In addition, upon the end of the Rockport Unit 2 lease, I&M’s 50% ownership share of Rockport Unit 2 and I&M’s purchased power from AEGCo related to Rockport Unit 2 will be a merchant resource for I&M until Rockport Unit 2 is retired. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. I&M has a similar proposal pending before the MPSC in I&M’s 2022 Michigan Integrated Resource Plan (IRP) filing. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Unit 2, it could reduce future net income and cash flows and impact financial condition.
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
Four participants in The American Electric Power System Retirement Plan (the Plan) has receivedfiled a letter written on behalfclass action complaint in December 2021 in the U.S. District Court for the Southern District of four participants (the Claimants) making a claim for additional plan benefitsOhio against AEPSC and purporting to advance such claims on behalf of a class.the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have assertedplaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) the companyAEP failed to provide required notice regarding the changes to the Plan. AEP has respondedAmong other relief, the Complaint seeks reformation of the Plan 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 Committeeprovide additional benefits and the Committee upheldrecovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for
additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the denial of claims. ManagementPlan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs have filed a motion for leave to file an amended complaint. AEP 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,AEP, with assistance from
outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We doManagement does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.
In August 2020, an AEP shareholder filed a putative class action lawsuit in the 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 allegesalleged 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 seekssought monetary damages, among other forms of relief. On May 10,In December 2021, the defendants filed a motion to dismissdistrict court issued an opinion and order dismissing the securities litigation for failurecomplaint with prejudice, determining that the complaint failed to state a claim andplead any actionable misrepresentations or omissions. The plaintiffs did not appeal the motion was fully briefed as of July 26, 2021. The Court has scheduled oral argument for November 23, 2021 on the motion to dismiss. 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.ruling.
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 threecourt entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed its motion to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the motion to dismiss with prejudice and plaintiffs have filed a notice of appeal with the New York appellate court. The two derivative actions pending in federal district court in Ohio have been consolidated and the plaintiffs in the consolidated action filed an amended complaint.AEP filed a motion to dismiss on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the motion to dismiss the securities litigation.consolidated derivative actions pending in Ohio federal district court. The fourth has been stayed until such time as the court determines to lift the stay. The companydefendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
OnIn 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 CompanyAEP 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 ofsince withdrawn the litigation demand, until the resolutionwhich is now terminated and 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.no further effect.
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing inquiry. AEP is cooperating fully with the SEC’s subpoena.investigation. Although the outcome of the SEC’s investigation cannot be predicted, management does 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 September 30, 2021,2022, the AEP System owned generating capacity of approximately 25,00025,300 MWs, of which approximately 12,10011,300 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$300 million to $700$500 million through 2027.2026.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizing proposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) potential state rules that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) actual performance of the pollution control technologies installed, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity, (g) compliance with the Federal EPA’s revised coal combustion residual rules and (g)(h) other factors. In addition, management continues to evaluate the economic feasibility of environmental investments on regulated and competitive plants.
Obligations under the New Source Review Litigation Consent Decree
In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years. The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOX emissions from the AEP System and various mitigation projects. The
consent decree has been modified sixseven times, for various reasons, most recently in 2020.2022. All of the environmental control equipment required by the consent decree has been installed.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. The primary regulatory programs that continue to drive investments in AEP’s existing generating units include: (a) periodic revisions to NAAQS and the development of SIPs to achieve 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 postponespostponed 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 NOX regional haze obligations for electric generating units in Texas. Additionally, the Federal EPA finalized an intrastate SO2 emissions trading program based on CSAPR allowance allocations. Legal challenges to these various rulemakings are pending in both the U.S. Court of Appeals for the Fifth Circuit and the U.S. Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation, although management supports the intrastate trading program as a compliance alternative to source-specific controls and has intervened in the litigation in support of the Federal EPA.
Cross-State Air Pollution Rule
CSAPR is a regional trading program designed to address interstate transport of emissions that contributed significantly to downwind non-attainment with the 1997 ozone and PM NAAQS. CSAPR relies on SO2 and NOX allowances 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 NOX budgets in 2021-2024. Several utilities and other entities potentially subject to the Federal EPA’s NOX regulations have challenged that final rule in the U.S. Court of Appeals for the District of Columbia Circuit and briefing is underway. Management cannot predict the outcome of that litigation, but believes it can meet the requirements of the rule in the near term, and is evaluating its compliance options for later years, when the budgets are further reduced. In addition, in February 2022, the EPA Administrator signed a proposed FIP for 2015 Ozone NAAQS that would further revise the ozone season NOX budgets under the existing CSAPR program. AEP is evaluating the proposed changes.
Climate Change, CO2 Regulation and Energy Policy
In 2019, the Affordable Clean Energy (ACE) rule established a framework for states to adopt standards of performance for utility boilers based on heat rate improvements for such boilers. However, in January 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded it to the Federal EPA. In October 2021 the United States Supreme Court granted certiorari and combined four separate petitions seeking review of the D.C. Circuit Court decisions. Oral arguments were held in February 2022 and on June 30, 2022, the United States Supreme Court reversed the D.C. Circuit Court’s decision and remanded for further proceedings. The Federal EPA must take some action before anything is required of the utilities as a result of this decision. At a minimum, if the Federal EPA intends to implement the ACE rule, it must conduct additional rulemaking to update its applicable deadlines, which have all passed. Alternatively, the Federal EPA may abandon the ACE rule and proceed to regulate greenhouse gases through a new rule, the scope of which is unknown. The Federal EPA has previously announced it expects to propose a new rule by spring of 2023. Management is unable to predict how the Federal EPA will respond to the court’s remand.
In 2018, the Federal EPA filed a proposed rule revising the standards for new sources and determined that partial carbon capture and storage is not the best system of emission reduction because it is not available throughout the U.S. and is not cost-effective. That rule has not been finalized. Management continues to actively monitor these rulemaking activities.
While no federal regulatory requirements to reduce CO2 emissions are in place, AEP has taken action to reduce and offset CO2 emissions from its generating fleet. AEP expects CO2 emissions from its operations to continue to decline due to the retirement of some of its coal-fired generation units, and actions taken to diversify the generation fleet and increase energy efficiency where there is regulatory support for such activities. The majority of the states where AEP has generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements that can assist in reducing carbon emissions. In April 2020, Virginia enacted clean energy legislation to allow the state to participate in the Regional Greenhouse Gas Initiative, 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,October 2022, AEP announced new intermediate and long-term CO2 emission reduction goals, based on the output of the company’s integrated resource plans, which take into account economics, customer demand, grid reliability and resiliency, regulations and the company’s current business strategy. The intermediate goal is anAEP adjusted its near-term carbon dioxide emission reduction target from a 2000 baseline to a 2005 baseline, upgraded its 80% reduction from 2000by 2030 target to include full Scope 1 emissions and accelerated its net-zero goal by five years to 2045. AEP’s total Scope 1 GHG emissions in 2021 were approximately 56 million metric tons CO2 emission levels from AEP generating facilities by 2030; the long-term goal is net-zero CO2 emissions from AEP generating facilities by 2050. AEP’s total estimated CO2 emissions in 2020 weree, approximately 44 million metric tons, a 73%63% reduction from AEP’s 2000 CO22005 Scope 1 GHG emissions. AEP has made significant progress in reducing CO2 emissions from its power generation fleet and expects its emissions to continue to decline. Technological advances, including energy storage, will determine how quickly AEP can achieve zero emissions while continuing to provide reliable, affordable power for customers.
Excessive costs to comply with future legislation or regulations have led to the announcement of early plant closures and could force AEP to close additional coal-fired generation facilities earlier than their estimated useful life. If AEP is unable to recover the costs of its investments, it would reduce future net income and cash flows and impact financial condition.
Coal Combustion Residual 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 | Company | | | Plant Name and Unit | | Generating Capacity | | | Net Book Value (a) | | Projected Retirement Date | | Company | | | Plant Name and Unit | | Generating Capacity | | | Net Book Value (a) | | Projected Retirement Date | |
| | | | | | (in MWs) | | | (in millions) | | | | | | | | | (in MWs) | | | (in millions) | | | |
AEGCo | AEGCo | | | Rockport Plant, Unit 1 | | 655 | | | $ | 232.0 | | | 2028 | | AEGCo | | | Rockport Plant, Unit 1 | | 655 | | | $ | 222.2 | | | 2028 | |
APCo | APCo | | | Amos | | 2,930 | | | 2,111.7 | | | 2040 | | APCo | | | Amos Plant | | 2,930 | | | 2,123.6 | | | 2040 | |
APCo | APCo | | | Mountaineer | | 1,320 | | | 962.3 | | | 2040 | | APCo | | | Mountaineer Plant | | 1,320 | | | 979.0 | | | 2040 | |
I&M | I&M | | | Rockport Plant, Unit 1 | | 655 | | | 525.1 | | (b) | 2028 | | I&M | | | Rockport Plant, Unit 1 | | 655 | | | 462.9 | | (b) | 2028 | |
KPCo | KPCo | | | Mitchell Plant | | 780 | | | 586.5 | | | 2040 | | KPCo | | | Mitchell Plant | | 780 | | | 575.6 | | | 2040 | |
SWEPCo | SWEPCo | | | Flint Creek Plant | | 258 | | | 269.2 | | | 2038 | | SWEPCo | | | Flint Creek Plant | | 258 | | | 263.6 | | | 2038 | |
WPCo | WPCo | | | Mitchell Plant | | 780 | | | 588.9 | | | 2040 | | WPCo | | | Mitchell Plant | | 780 | | | 603.6 | | | 2040 | |
(a)Net book value before cost of removal including CWIP and inventory.
(b)Amount includes a $176$153 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 addition, AGR owns Cardinal Plant, Unit 1January 2022, the Federal EPA began responding to applications for extension requests and has proposed to deny several extension requests based on allegations that the utilities that received such responses are not in compliance with the CCR Rule. The Federal EPA’s allegations of noncompliance rely on new interpretations of the CCR Rule requirements. The actions of the Federal EPA have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit as unlawful rulemaking that revises the existing CCR Rule requirements without proper notice and without opportunity for comment. Management is unable to predict the outcome of that litigation. On July 12, 2022, the Federal EPA proposed conditional approval of the pending extension request for the Mountaineer Plant. The Federal EPA has not yet proposed any action on the other pending extension requests submitted by AEP; however, statements made by the Federal EPA in proposed denials of extension requests submitted by other utilities indicate that there is a competitive generation unit. A nonaffiliate owns Cardinal Plant, Unit 2 and Unit 3 and operates all threerisk that the Federal EPA may similarly conclude that AEP is not eligible for an extension of time to cease use of those CCR impoundments and/or that one or more of AEP’s facilities is not in compliance with the CCR Rule. If that occurs, AEP may incur material additional costs to change its plans for complying with the CCR Rule, including the potential to have to temporarily cease operation of one or more facilities until an acceptable compliance alternative can be implemented. Such temporary cessation of operation could materially impact the cost of serving customers of the affected utility. Further, actions by the Federal EPA could require AEP to remove coal ash from CCR units that have already been closed in accordance with state law programs or could require AEP to incur costs related to CCR units at the Cardinal Plant. The nonaffiliate filed an application for additional time to develop alternative disposal capacity for the Cardinal Plant. As of September 30, 2021, the net book value of Cardinal Plant, Unit 1, including materialsvarious active and supplies and CWIP, was approximately $43 million.legacy facilities.
Closure and post-closure costs have been included in ARO in accordance with the requirements in the Federal EPA’s final CCR rule. Additional ARO revisions will occur on a site-by-site basis if groundwater monitoring activities conclude that corrective actions are required to mitigate groundwater impacts. AEP may incur significant additional costs complying with the Federal EPA’s CCR Rule including costs to upgrade or close and replace surface impoundments and landfills used to manage CCR and to conduct any required remedial actions including removal of coal ash. If additional costs are incurred and AEP is unable to obtain cost recovery, it would reduce
future net income and cash flows and impact financial condition. Management will continue to participate in rulemaking activities and make adjustments based on new federal and state requirements affecting its ash disposal units.
The second option is a retirement option, which providesto obtain an extension of the April 11, 2021 deadline to cease operation of unlined impoundments allows a generating facility an extendedto continue operating timeits existing impoundments without developing alternative CCR disposal.disposal, provided the facility commits to cease combustion of coal by a date certain. Under the retirementthis option, a generating facility would have until October 17, 2023 to cease operationcoal-fired operations and to close CCR storage ponds 40 acres or less in size, or through October 17, 2028 for facilities with CCR storage ponds greater than 40 acres in size. Pursuant to this option, AEP informed the Federal EPA of its intent to retire the Pirkey Power Plant and cease using coal at the Welsh Plant:
| Company | Company | | | Plant Name and Unit | | Generating Capacity | | | Net Investment (a) | | Accelerated Depreciation Regulatory Asset | | Projected Retirement Date | | Company | | | Plant Name and Unit | | Generating Capacity | | | Net Investment (a) | | Accelerated Depreciation Regulatory Asset | | Projected Retirement Date | |
| | | | | | (in MWs) | | | (in millions) | | | | | | | | | (in MWs) | | | (in millions) | | | |
SWEPCo | SWEPCo | | | Pirkey Power Plant | | 580 | | | $ | 135.4 | | | $ | 68.0 | | | 2023 (b) | | SWEPCo | | | Pirkey Plant | | 580 | | | $ | 65.0 | | | $ | 150.7 | | | 2023 | (b) | |
SWEPCo | SWEPCo | | | Welsh Plants, Units 1 and 3 | | 1,053 | | | 493.7 | | | 35.6 | | | 2028 (c)(d) | | SWEPCo | | | Welsh Plant, Units 1 and 3 | | 1,053 | | | 432.3 | | | 75.7 | | | 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 conductTo date, the Federal EPA has not taken any required remedial actions.action on these pending extension requests. Under the retirementsecond option above, AEP may need to recover remaining depreciation and estimated closure costs associated with retiringthese 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 retiringthese 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 onfor 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 forFor affected facilities that must install additional technologies to meet the ELG rule limits, permit modifications were filed in January 2021 that reflect the outcome of that assessment. We continueAEP continues to work with state agencies to finalize permit terms and conditions. Other facilities opted to file Notices of Planned Participation (NOPP), pursuant to which the facilities are not required to install additional controls to meet ELG limits provided they make commitments to cease coal combustion by a date certain. The Federal EPA has announced its intention to reconsider the 2020 rule and to further revise limits applicable to discharges of landfill and impoundment leachate. A proposed rule is expected in late 2022 or early 2023. Management cannot predict whether the Federal EPA will actually finalize further revisions or what such revisions might be, but will continue to monitor this issue and will participate in further rulemaking activities as they arise.
In August 2021, the Federal EPA and the Army Corps of Engineers announced their plan to reconsider and revise the Navigable Waters Protection Rule, which defines “waters of the United States” under the Clean Water Act. Shortly thereafter, the United States District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule, which had the effect of reinstating the prior, much broader, version of the rule. Because the scope of waters subject to the Federal EPA and Army Corps of Engineers jurisdictions is broader under the prior rule, permitting decisions made in recent years are subject to reevaluation; permits may now be necessary where
none were previously required, and issued permits may need to be reopened to impose additional obligations. In December 2021, the Federal EPA proposed a rule that would roll back the definition of “waters of the United States” to the pre-2015 definition. The Federal EPA also announced that it would be considering further changes through a future rulemaking, which would build upon the foundation of the proposed rule. Management will continue to monitor rulemaking on this issue.
In October 2022, the U.S. Supreme Court heard an appeal related to the scope of “waters of the United States,” specifically which wetlands can be regulated as waters of the United States. Management cannot predict the outcome of that litigation.
CCR and ELG Compliance Plan Filings
Mitchell Plant (Applies to AEP)
KPCo and WPCo each own a 50% interest in the Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.
In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.
In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petitionThe WVPSC’s order further states that unless KPCo pays for reconsideration atits share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the WVPSC requesting clarification on certain aspectsbenefit of the order, primarily thecapacity and energy made possible by those improvements and operating Mitchell Plant beyond 2028 should benefit only West Virginia jurisdictional allocation of future operating expenses and plantcustomers who have shared in paying for those costs.
As of September 30, 2021, the Mitchell Plant ELG investment balance in CWIP was $3 million split equally between KPCo and WPCo. As of September 30, 2021, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $587 million.
If any of the ELG 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.
Amos and Mountaineer Plants (Applies to AEP and APCo)
In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting regulatory approvals necessary to recover the estimated $240 million investment needed to implement CCR and ELG compliance plans and seek recovery of the estimated $240 million investment for 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, that APCo close these generating facilities at the end of 2028.
In August 2021, the Virginia SCC issued an order approving APCo’s request to constructrecovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order also denied APCo’s request to constructrecover the cost of ELG investments and denied recovery of previously incurred ELG costs.costs, but did not preclude APCo may refilefrom refiling for approval. In March 2022, APCo refiled for approval to recover the cost of the ELG investments and previously incurred ELG costs. Intervenor testimony was submitted in August 2022 recommending the denial of ELG cost recovery. In October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC approve recovery of APCo’s requested ELG investment
costs at a later date.Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC in the fourth quarter of 2022.
Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In SeptemberOctober 2021, APCo submitted a filing with the WVPSCdue to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the initial rejection by the Virginia SCC of the Virginia jurisdictional share of thepreviously rejecting those ELG investments, APCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plants. In October 2021, the WVPSC affirmed its August 2021issued an order approving the construction of CCR/ELG investments and directeddirecting APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC’s order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. InThe October 2021 an intervenor filed a petitionorder further states that unless the Virginia jurisdictional customers of APCo pay for reconsideration attheir share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the WVPSC requesting clarification on certain aspectsbenefit of the order, primarilycapacity and energy made possible by those improvements and operating the Amos and Mountaineer Plants beyond 2028 should benefit only West Virginia and FERC jurisdictional allocation of future operating expenses and plantcustomers who have shared in paying for those costs.
APCo expects the total Amos and Mountaineer Plant ELG investment, includingexcluding AFUDC, to be approximately $177$162 million. As of September 30, 2021,2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $19$62 million.
If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plantsPlants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.
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, costsremediation 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 September 30, 2021,2022, of generating facilities retired or planned for early retirement:retirement in advance of the retirement date currently authorized for ratemaking purposes:
| Company | Company | | Plant | | | Net Investment (a) | | Accelerated Depreciation Regulatory Asset | | | Actual/Projected Retirement Date | | Current Authorized Recovery Period | | Annual Depreciation (b) | | Company | | Plant | | | Net Investment (a) | | Accelerated Depreciation Regulatory Asset | | | Actual/Projected Retirement Date | | Current Authorized Recovery Period | | Annual Depreciation (b) | |
| | | | | | (in millions) | | | | | | (in millions) | | | | | | | (in millions) | | | | | | (in millions) | |
PSO | PSO | | Northeastern Plant, Unit 3 | | | $ | 175.1 | | | $ | 123.6 | | | | 2026 | | (c) | | $ | 14.9 | | | PSO | | Northeastern Plant, Unit 3 | | | $ | 143.7 | | | $ | 141.4 | | | | 2026 | | (c) | | $ | 14.9 | | |
PSO | | Oklaunion Power Station | | | — | | | 33.0 | | | | 2020 | | (d) | | 2.0 | | | |
| SWEPCo | SWEPCo | | Dolet Hills Power Station | | | 13.0 | | | 126.8 | | | | 2021 | | (e) | | 7.7 | | | SWEPCo | | Dolet Hills Power Station | | | — | | | 54.7 | | | | 2021 | | (d) | | — | | |
SWEPCo | SWEPCo | | Pirkey Power Plant | | | 135.4 | | | 68.0 | | | | 2023 | | (f) | | 13.4 | | | SWEPCo | | Pirkey Plant | | | 65.0 | | | 150.7 | | | | 2023 | | (e) | | 12.5 | | |
SWEPCo | SWEPCo | | Welsh Plant, Units 1 and 3 | | | 493.7 | | | 35.6 | | | | 2028 (g) | | (h) | | 32.9 | | | SWEPCo | | Welsh Plant, Units 1 and 3 | | | 432.3 | | | 75.7 | | | | 2028 | (f) | | (g) | | 39.8 | | |
SWEPCo | SWEPCo | | Welsh Plant, Unit 2 | | | — | | | 35.2 | | | | 2016 | | (i) | | — | | | SWEPCo | | Welsh Plant, Unit 2 | | | — | | | 35.2 | | | | 2016 | | (h) | | — | | |
|
(a)Net book value including CWIP excluding cost of removal and materials and supplies.
(b)These amounts represent the amount of annual depreciation that has been collected from customers over the prior 12-month period.
(c)Northeastern Plant, Unit 3 is currently being recovered through 2040.
(d)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 Texas jurisdiction. In December 2021, the PUCT authorized the recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station through 2046 without providing a return on the investment which resulted in a disallowance of $12 million. In May 2022, the APSC authorized the recovery of SWEPCo’s Arkansas and Texas jurisdictions.jurisdictional share of the Dolet Hills Power Station through 2027 without providing a return on investment, which resulted in an immaterial disallowance in the second quarter of 2022. See Note 4 - Rate Matters for additional information.
(f)(e)Pirkey Power Plant is currently being recovered through 2025 in the Louisiana jurisdiction and through 2045 in the Arkansas and Texas jurisdictions.
(g)(f)In November 2020, management announced it will cease using coal at the Welsh Plant in 2028.
(h)(g)Welsh Plant, Unit 1 is being recovered through 2027 in the Louisiana jurisdiction and through 2037 in the Arkansas and Texas jurisdictions. Welsh Plant, Unit 3 is being recovered through 2032 in the Louisiana jurisdiction and through 2042 in the Arkansas and Texas jurisdictions.
(i)(h)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 areis not deemed recoverable, it could materially reduce future net income, cash flows and impact financial condition.
RESULTS OF OPERATIONS
SEGMENTS
AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
AEP’s reportable segments and their related business activities are outlined below:
Vertically Integrated Utilities
•Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.
Transmission and Distribution Utilities
•Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEP Texas and OPCo.
•OPCo purchases energy and capacity at auction to serve standard service offer customers and provides transmission and distribution services for all connected load.
AEP Transmission Holdco
•Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved ROE.
•Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved ROE.
Generation & Marketing
•Contracted renewable energy investments and management services.
•Marketing, risk management and retail activities in ERCOT, MISO, PJM and SPP.
•Competitive generation in PJM.
The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
The following discussion of AEP’s results of operations by operating segment includes an analysis of Gross Margin, which is a non-GAAP financial measure. Gross Margin includes Total Revenues less the costs of Fuel and Other Consumables Used for Electric Generation, as well as Purchased Electricity for Resale, as presented in the Registrants’ statements of income as applicable. Under the various state utility rate making processes, these expenses are generally reimbursable directly from and billed to customers. As a result, they do not typically impact Operating Income or Earnings Attributable to AEP Common Shareholders. Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze AEP’s financial performance in that it excludes the effect on Total Revenues caused by volatility in these expenses. Operating Income, which is presented in accordance with GAAP in AEP’s statements of income, is the most directly comparable GAAP financial measure to the presentation of Gross Margin. AEP’s definition of Gross Margin may not be directly comparable to similarly titled financial measures used by other companies.
The following table presents Earnings (Loss) Attributable to AEP Common Shareholders by segment:
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Vertically Integrated Utilities | Vertically Integrated Utilities | $ | 437.7 | | | $ | 393.5 | | | $ | 936.3 | | | $ | 894.7 | | Vertically Integrated Utilities | $ | 476.9 | | | $ | 437.7 | | | $ | 1,076.3 | | | $ | 936.3 | |
Transmission and Distribution Utilities | Transmission and Distribution Utilities | 155.9 | | | 147.4 | | | 424.0 | | | 403.1 | | Transmission and Distribution Utilities | 165.5 | | | 155.9 | | | 483.1 | | | 424.0 | |
AEP Transmission Holdco | AEP Transmission Holdco | 166.8 | | | 138.3 | | | 507.5 | | | 370.4 | | AEP Transmission Holdco | 170.5 | | | 166.8 | | | 485.4 | | | 507.5 | |
Generation & Marketing | Generation & Marketing | 100.7 | | | 116.7 | | | 189.7 | | | 211.0 | | Generation & Marketing | 97.5 | | | 100.7 | | | 284.3 | | | 189.7 | |
Corporate and Other | Corporate and Other | (65.1) | | | (47.3) | | | (108.3) | | | (114.6) | | Corporate and Other | (226.7) | | | (65.1) | | | (406.2) | | | (108.3) | |
Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | $ | 796.0 | | | $ | 748.6 | | | $ | 1,949.2 | | | $ | 1,764.6 | | Earnings Attributable to AEP Common Shareholders | $ | 683.7 | | | $ | 796.0 | | | $ | 1,922.9 | | | $ | 1,949.2 | |
AEP CONSOLIDATED
Third Quarter of 20212022 Compared to Third Quarter of 20202021
Earnings Attributable to AEP Common Shareholders increaseddecreased from $749 million in 2020 to $796 million in 2021 to $684 million in 2022 primarily due to:
•A loss on the expected sale of the Kentucky Operations.
•An increase in depreciation expense due to continued investment.
This decrease was partially offset by:
•Favorable rate proceedings in AEP’s various jurisdictions.
Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
Earnings Attributable to AEP Common Shareholders decreased from $1,949 million in 2021 to $1,923 million in 2022 primarily due to:
•A loss on the expected sale of the Kentucky Operations.
•An impairment of AEP’s equity investment in Flat Ridge 2.
•An increase in transmission investment, which resulted in higher revenues and income.depreciation expense due to continued investment.
These increasesdecreases were partially offset by:
•An increase in Other Operation and Maintenance expenses driven byA gain on the COVID-19 pandemic which resulted in lower expenses in the second quartersale of 2020.
•The recognition of a discrete tax adjustment in 2020 which was attributable to the 5-year net operating loss carryback provision of the CARES Act.
•Unrealized losses on AEP’s investment in ChargePoint.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
Earnings Attributable to AEP Common Shareholders increased from $1,765 million in 2020 to $1,949 million in 2021 primarily due to:
mineral rights.
•Favorable rate proceedings in AEP’s various jurisdictions.
•An increase in weather-related usage.Increased sales volumes.
•An increase in transmission investment, which resulted inFavorable mark-to-market economic hedge activity driven by higher revenues and income.commodity prices.
These increases were partially offset by:
•An increase in Other Operation and Maintenance expenses drivenAEP’s results of operations by the COVID-19 pandemic which resulted in lower expenses in 2020.
•The recognition of a discrete tax adjustment in 2020 which was attributable to the 5-year net operating loss carryback provision of the CARES Act.segment are discussed below.
VERTICALLY INTEGRATED UTILITIES
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
Vertically Integrated Utilities | Vertically Integrated Utilities | | 2021 | | 2020 | | 2021 | | 2020 | Vertically Integrated Utilities | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
Revenues | Revenues | | $ | 2,759.3 | | | $ | 2,434.8 | | | $ | 7,557.2 | | | $ | 6,753.5 | | Revenues | | $ | 3,226.3 | | | $ | 2,759.3 | | | $ | 8,562.2 | | | $ | 7,557.2 | |
Fuel and Purchased Electricity | Fuel and Purchased Electricity | | 855.3 | | | 693.7 | | | 2,364.7 | | | 1,947.0 | | Fuel and Purchased Electricity | | 1,191.9 | | | 855.3 | | | 2,895.8 | | | 2,364.7 | |
| Gross Margin | Gross Margin | | 1,904.0 | | | 1,741.1 | | | 5,192.5 | | | 4,806.5 | | Gross Margin | | 2,034.4 | | | 1,904.0 | | | 5,666.4 | | | 5,192.5 | |
Other Operation and Maintenance | Other Operation and Maintenance | | 796.9 | | | 715.9 | | | 2,240.6 | | | 2,031.8 | | Other Operation and Maintenance | | 834.0 | | | 796.9 | | | 2,383.1 | | | 2,240.6 | |
| Asset Impairments and Other Related Charges | | Asset Impairments and Other Related Charges | | 24.9 | | | — | | | 24.9 | | | — | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | (37.0) | | | — | | | (37.0) | | | — | |
| Depreciation and Amortization | Depreciation and Amortization | | 436.3 | | | 398.8 | | | 1,302.2 | | | 1,173.8 | | Depreciation and Amortization | | 520.6 | | | 436.3 | | | 1,525.0 | | | 1,302.2 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 124.1 | | | 121.0 | | | 375.6 | | | 355.6 | | Taxes Other Than Income Taxes | | 130.1 | | | 124.1 | | | 383.9 | | | 375.6 | |
Operating Income | Operating Income | | 546.7 | | | 505.4 | | | 1,274.1 | | | 1,245.3 | | Operating Income | | 561.8 | | | 546.7 | | | 1,386.5 | | | 1,274.1 | |
| Other Income (Expense) | | 4.1 | | | (0.7) | | | 9.9 | | | 2.3 | | |
Other Income | | Other Income | | 9.0 | | | 4.1 | | | 24.9 | | | 9.9 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 9.6 | | | 15.9 | | | 30.3 | | | 33.1 | | Allowance for Equity Funds Used During Construction | | 6.0 | | | 9.6 | | | 20.4 | | | 30.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 17.0 | | | 16.9 | | | 51.0 | | | 50.9 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 27.4 | | | 17.0 | | | 82.4 | | | 51.0 | |
Interest Expense | Interest Expense | | (144.3) | | | (140.2) | | | (425.5) | | | (426.5) | | Interest Expense | | (168.8) | | | (144.3) | | | (477.1) | | | (425.5) | |
Income Before Income Tax Expense (Benefit) and Equity Earnings | Income Before Income Tax Expense (Benefit) and Equity Earnings | | 433.1 | | | 397.3 | | | 939.8 | | | 905.1 | | Income Before Income Tax Expense (Benefit) and Equity Earnings | | 435.4 | | | 433.1 | | | 1,037.1 | | | 939.8 | |
Income Tax Expense (Benefit) | Income Tax Expense (Benefit) | | (4.6) | | | 3.8 | | | 3.4 | | | 10.5 | | Income Tax Expense (Benefit) | | (41.2) | | | (4.6) | | | (41.3) | | | 3.4 | |
Equity Earnings of Unconsolidated Subsidiary | Equity Earnings of Unconsolidated Subsidiary | | 1.0 | | | 0.7 | | | 2.5 | | | 2.2 | | Equity Earnings of Unconsolidated Subsidiary | | 0.3 | | | 1.0 | | | 1.0 | | | 2.5 | |
Net Income | Net Income | | 438.7 | | | 394.2 | | | 938.9 | | | 896.8 | | Net Income | | 476.9 | | | 438.7 | | | 1,079.4 | | | 938.9 | |
Net Income Attributable to Noncontrolling Interests | Net Income Attributable to Noncontrolling Interests | | 1.0 | | | 0.7 | | | 2.6 | | | 2.1 | | Net Income Attributable to Noncontrolling Interests | | — | | | 1.0 | | | 3.1 | | | 2.6 | |
Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | | $ | 437.7 | | | $ | 393.5 | | | $ | 936.3 | | | $ | 894.7 | | Earnings Attributable to AEP Common Shareholders | | $ | 476.9 | | | $ | 437.7 | | | $ | 1,076.3 | | | $ | 936.3 | |
Summary of KWh Energy Sales for Vertically Integrated Utilities
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions of KWhs) | | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | | Retail: | | | | | | | | |
Residential | Residential | | 9,119 | | | 9,066 | | | 25,125 | | | 24,304 | | Residential | | 9,115 | | | 9,119 | | | 25,379 | | | 25,125 | |
Commercial | Commercial | | 6,468 | | | 6,257 | | | 17,396 | | | 16,773 | | Commercial | | 6,640 | | | 6,468 | | | 18,069 | | | 17,396 | |
Industrial | Industrial | | 8,485 | | | 8,161 | | | 24,798 | | | 24,335 | | Industrial | | 8,862 | | | 8,485 | | | 25,930 | | | 24,798 | |
Miscellaneous | Miscellaneous | | 604 | | | 595 | | | 1,672 | | | 1,636 | | Miscellaneous | | 623 | | | 604 | | | 1,745 | | | 1,672 | |
Total Retail | Total Retail | | 24,676 | | | 24,079 | | | 68,991 | | | 67,048 | | Total Retail | | 25,240 | | | 24,676 | | | 71,123 | | | 68,991 | |
| Wholesale (a) | Wholesale (a) | | 5,713 | | | 4,574 | | | 14,842 | | | 13,116 | | Wholesale (a) | | 4,254 | | | 5,713 | | | 12,388 | | | 14,842 | |
| Total KWhs | Total KWhs | | 30,389 | | | 28,653 | | | 83,833 | | | 80,164 | | Total KWhs | | 29,494 | | | 30,389 | | | 83,511 | | | 83,833 | |
(a)Includes Off-system Sales, municipalities and cooperatives, unit power and other wholesale customers.
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in degree days) | | | (in degree days) |
Eastern Region | Eastern Region | | | | | | | | | Eastern Region | | | | | | | | |
Actual – Heating (a) | Actual – Heating (a) | | 1 | | | 3 | | | 1,710 | | | 1,456 | | Actual – Heating (a) | | 8 | | | 1 | | | 1,750 | | | 1,710 | |
Normal – Heating (b) | Normal – Heating (b) | | 4 | | | 4 | | | 1,742 | | | 1,752 | | Normal – Heating (b) | | 4 | | | 4 | | | 1,748 | | | 1,742 | |
| Actual – Cooling (c) | Actual – Cooling (c) | | 847 | | | 867 | | | 1,209 | | | 1,204 | | Actual – Cooling (c) | | 783 | | | 847 | | | 1,178 | | | 1,209 | |
Normal – Cooling (b) | Normal – Cooling (b) | | 744 | | | 739 | | | 1,087 | | | 1,081 | | Normal – Cooling (b) | | 745 | | | 744 | | | 1,082 | | | 1,087 | |
| Western Region | Western Region | | | | | | | | | Western Region | | | | | | | | |
Actual – Heating (a) | Actual – Heating (a) | | — | | | 1 | | | 993 | | | 699 | | Actual – Heating (a) | | — | | | — | | | 930 | | | 993 | |
Normal – Heating (b) | Normal – Heating (b) | | 1 | | | 1 | | | 901 | | | 902 | | Normal – Heating (b) | | — | | | 1 | | | 906 | | | 901 | |
| Actual – Cooling (c) | Actual – Cooling (c) | | 1,485 | | | 1,291 | | | 2,163 | | | 2,015 | | Actual – Cooling (c) | | 1,653 | | | 1,485 | | | 2,558 | | | 2,163 | |
Normal – Cooling (b) | Normal – Cooling (b) | | 1,410 | | | 1,416 | | | 2,137 | | | 2,144 | | Normal – Cooling (b) | | 1,413 | | | 1,410 | | | 2,134 | | | 2,137 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 393.5437.7 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 142.292.7 | |
Margins from Off-system Sales | | (0.1)8.3 | |
Transmission Revenues | | 18.221.9 | |
Other Revenues | | 2.67.5 | |
Total Change in Gross Margin | | 162.9130.4 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (81.0)(37.1) | |
Asset Impairments and Other Related Charges | | (24.9) | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | 37.0 | |
Depreciation and Amortization | | (37.5)(84.3) | |
Taxes Other Than Income Taxes | | (3.1)(6.0) | |
| | |
| | |
Other Income | | 4.84.9 | |
Allowance for Equity Funds Used During Construction | | (6.3)(3.6) | |
Non-Service Cost Components of Net Periodic Pension Cost | | 0.110.4 | |
Interest Expense | | (4.1)(24.5) | |
Total Change in Expenses and Other | | (127.1)(128.1) | |
| | |
Income Tax ExpenseBenefit | | 8.436.6 | |
Equity Earnings of Unconsolidated Subsidiary | | 0.3 (0.7) | |
Net Income Attributable to Noncontrolling Interests | | (0.3)1.0 | |
| | |
Third Quarter of 20212022 | | $ | 437.7476.9 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased $142$93 million primarily due to the following:
•A $42$47 million increase at APCo and WPCoPSO due to a $26 million increase in base rate revenues and a $21 million increase in rider revenues primarily in Virginia. This increase wasrevenues. These increases were partially offset in other expense items below.
•A $40 million increase at I&MSWEPCo primarily due to base rate revenue increases in Texas and Arkansas and an increase in rider revenues and the reversal of a provision for refund. This increase wasin all jurisdictions. These increases were partially offset in other expense items below.
•A $24 million increase in weather-related usage primarily in the residential class.
•A $22 million increase at APCo and WPCo due to an increase in revenue from rate riders at PSO.rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $15 million increase at I&M primarily due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. Thisan increase was partially offset in Income Tax Expense below.
•An $11 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.
•A $9An $11 million increase at KPCo due to base rate case revenues implemented in January 2021.weather-related usage primarily in the residential class.
These increases were partially offset by:
•A $15 million decrease in weather-normalized retail margins driven by a $26 million decrease in the residential class partially offset by a $10 million increase in the industrial and commercial classes.
•A $9$47 million decrease at PSO due toand SWEPCo resulting from the NCWF PTC benefits provided to customers.customers through fuel clause mechanisms. This decrease iswas partially offset in Income Tax Expense.Benefit below.
•An $8A $10 million decrease in deferred fuel at APCo and WPCoweather-normalized retail margins primarily in the residential class.
•Margins from Off-system Sales increased $8 million primarily due to the timing of recoverable PJM expenses.following:
•A $7 million increase due to an increase in Turk Plant merchant sales at SWEPCo.
•A $3 million increase at APCo primarily due to increased generation and strong market pricing.
•Transmission Revenues increased $18$22 million primarily due to:to continued investment in transmission assets and increased load.
•AnOther Revenues increased $8 million increaseprimarily due to increased transmission investment at APCo. This increase is partially offset in Depreciation and Amortization expenses below.
•A $7 millionan increase in load and transmission investment at SWEPCo.pole attachment rental revenue.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $81$37 million primarily due to the following:
•A $58$15 million increase in PJM transmission service expenses.
•A $23 millionservices. This increase was partially offset in vegetation management expenses.
•A $17 million increase in administrative and general expenses.Retail Margins above.
•A $13 million increase in SPP transmission serviceservices. This increase was partially offset in Retail Margins above.
•An $11 million increase due to the expensing of cancelled capital projects.
•An $11 million increase in generation expenses primarily due to plant outages and maintenance at APCo and I&M.
•A $6 million increase in storm restoration expenses.
•A $5 million increase in distribution system improvements across multiple operating companies.
•A $5 million increase in Energy Efficiency/Demand Response expenses. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $34$36 million decrease due to the modification of the Rockport Plant, Unit 2 lease which resulted in employee-related expenses.a change in lease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease is offset in Depreciation and Amortization expense below.
•Asset Impairments and Other Related Charges increased $25 million at APCo due to the write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.
•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million at APCo due to the establishment of a regulatory asset based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $38$84 million primarily due to the following:
•A $45 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo and the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.
•A $39 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a change in lease classification from an increaseoperating lease to a finance lease in depreciation ratesDecember 2021 at APCo.AEGCo and I&M. This increase was partially offset in Gross MarginOther Operation and Maintenance expenses above.
•Taxes Other Than Income Taxes increased $6 million due to the following:
•A $9 million increase at PSO and SWEPCo primarily due to increased property taxes and a new infrastructure fee at PSO implemented by the City of Tulsa in March 2022. This increase was partially offset in Retail Margins above.
This increase was partially offset by:
•A $5 million decrease at I&M primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This decrease was partially offset in Retail Margins above.
•Other Income increased $5 million at PSO primarily relateddue to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event at SWEPCo.event.
•Allowance for Equity Funds Used During Construction decreased $6$4 million primarily due to a decrease in AFUDC equity rates at APCo.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $10 million primarily due to an increase in discount rates, an increase in the adoption of the FERC’s temporary AFUDC waiver which was implementedexpected return on plan assets and favorable plan returns in July 2020 retroactive to March 2020.2021.
•Interest Expense increased $4$25 million primarily due to increasedhigher long-term debt balances at I&MAPCo, PSO and SWEPCo.SWEPCo, increased Advances from Affiliates at SWEPCo and higher interest rates at APCo.
•Income Tax ExpenseBenefit decreased $8increased $37 million primarily due to an increase in PTCs partially offset by a decrease in state income tax expense and an increase in PTC. This decrease wasamortization of Excess ADIT. These items were partially offset by an increase in pretax book income and a decrease in parent company loss benefit.Retail Margins above.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 894.7936.3 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 336.7404.6 | |
Margins from Off-system Sales | | 23.7 (18.9) | |
Transmission Revenues | | 29.466.8 | |
Other Revenues | | (3.8)21.4 | |
Total Change in Gross Margin | | 386.0473.9 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (208.8)(142.5) | |
Asset Impairments and Other Related Charges | | (24.9) | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | 37.0 | |
Depreciation and Amortization | | (128.4)(222.8) | |
Taxes Other Than Income Taxes | | (20.0)(8.3) | |
| | |
| | |
Other Income | | 7.615.0 | |
Allowance for Equity Funds Used During Construction | | (2.8)(9.9) | |
Non-Service Cost Components of Net Periodic Pension Cost | | 0.131.4 | |
Interest Expense | | 1.0 (51.6) | |
Total Change in Expenses and Other | | (351.3)(376.6) | |
| | |
Income Tax Expense | | 7.144.7 | |
Equity Earnings of Unconsolidated Subsidiary | | 0.3 (1.5) | |
Net Income Attributable to Noncontrolling Interests | | (0.5) | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 936.31,076.3 | |
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 Margins increased $337$405 million primarily due to the following:
•An $88 million increase at I&M due to the annual wholesale formula rate true-up, an increase in Indiana and Michigan base rate revenues and an increase in rider revenues. This increase was partially offset in other expense items below.
•An $84 million increase in weather-related usage primarily in the residential class.
•���A $66$111 million increase at APCo and WPCo due to an increase in rider revenuerevenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $41$95 million increase at PSO due to a $51 million increase in base rate revenues and a $44 million increase in rider revenues. These increases were partially offset in other expense items below.
•An $80 million increase at SWEPCo primarily due to base rate revenue increases in Texas and Arkansas and an increase in rider revenues in all retail jurisdictions. These increases were partially offset in other expense items below.
•A $43 million increase at I&M due to an increase in rider revenues offset by lower wholesale true-ups. This increase was partially offset in other expense items below.
•A $38$41 million increase at KPCo due to rider revenues. This increase was partially offset in other expense items below.weather-related usage primarily in the residential class.
•A $20 million increase at KPCo due to base rate case revenues implemented in January 2021.
•A $13$35 million increase in municipal and cooperative revenues at SWEPCoweather-normalized retail margins primarily due toin the February 2021 severe winter weather event.
•A $12 million increase due to lower customer refunds related to Tax Reform primarily at APCo and WPCo. This increase was partially offset in Income Tax Expense below.
•A $10 million increase in recoverable fuel costs at SWEPCo primarily due to timing of recovery.
•A $6 million increase in municipal and cooperative revenues at SWEPCo primarily due to the annual generation formula rate true-up.
commercial class.
These increases were partially offset by:
•A $32 million decrease in weather-normalized retail margins primarily in the residential class.
•A $24 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract at I&M.
•An $11$62 million decrease at PSO due toand SWEPCo resulting from the NCWF PTC benefits provided to customers.customers through fuel clause mechanisms. This decrease iswas partially offset in Income Tax Expense.Expense below.
•Margins from Off-system Sales increased $24decreased $19 million primarily due to the following:
•A $10 million decrease due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event at SWEPCo.
•A $7 million decrease at KPCo due to a change in the OSS sharing arrangement.
•Transmission Revenues increased $29$67 million primarily due to the following:
•A $22$47 million increase due toin continued investment in transmission assets and increased transmission investment at APCo. This increase is partially offset in Depreciation and Amortization expenses below.load.
•A $12$20 million increase due to increased load and increased transmission investment at SWEPCo.
These increases were partially offset by:
•A $7 million decrease as a result of the transmissionin formula rate true-up.true-up activity.
•Other Revenues decreased $4increased $21 million primarily due to the following:
•A $6$7 million decreaseincrease at PSOAPCo primarily due to lower business development revenue. This decreaseincrease was partially offset in Other Operation and Maintenance expenses below.
•A $2 million decrease primarily due to lower pole attachment revenue at KPCo.
These decreases were partially offset by:
•A $4$6 million increase at I&M primarily due to ana gain on sale of allowances and economic hedging activities. The gain on the sale of allowances was partially offset in Retail Margins above.
•A $3 million increase in reconnection feesat KPCo primarily due to rental revenue from pole attachments, a gain on the sale of allowances and joint license agreements.business development revenue.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $209$143 million primarily due to the following:
•A $131$96 million increase in PJM transmission service expenses including the annual formula rate true-up.services. This increase was partially offset in Retail Margins above.
•A $56$62 million increase in vegetation managementgeneration expenses primarily due to outages and maintenance at APCo, I&M and PSO.
•A $25 million increase in SPP transmission services. This increase was partially offset in Retail Margins above.
•A $16 million increase in storm restoration expenses.
•A $50$12 million increase in SPP transmission service expenses including the annual formula rate true-up.
•A $10 millionEnergy Efficiency/Demand Response expenses. This increase was partially offset in administrative overheads.Retail Margins above.
•An $8$11 million increase in employee-related expenses.
•An $11 million increase due to the capitalizationexpensing of previously expensed North Central Wind Energy Facilities costs at PSO and SWEPCo in 2020.cancelled capital projects.
These increases were partially offset by:
•A $20$108 million decrease primarily due to the modification of the Rockport Plant, Unit 2 lease which resulted in a decreasechange in Indiana jurisdictional Demand Side Management expenseslease classification from an operating lease to a finance lease in December 2021 at AEGCo and I&M. This decrease wasis offset in Retail Margins above.Depreciation and Amortization expense below.
•A $14Asset Impairments and Other Related Charges increased $25 million decreaseat APCo due to the write-off of a regulatory asset in employee-related expenses.accordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial review.
•An $11Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million decrease in factoring expenses.at APCo due to the establishment of a regulatory asset based on an August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $128$223 million primarily due to the following:
•A $117 million increase due to the modification of the Rockport Plant, Unit 2 lease which resulted in a higher depreciable basechange in lease classification from an operating lease to a finance lease in December 2021 at APCo, I&M, PSO and SWEPCo and increased depreciation rates at APCoAEGCo and I&M. This increase was partially offset in Gross MarginOther Operation and Maintenance expenses above.
•A $106 million increase due to a higher depreciable base primarily at APCo, I&M, PSO and SWEPCo, the implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO and in Arkansas and Texas for SWEPCo. The increase due to implementation of new rates and the timing of refunds to customers under rate rider mechanisms at PSO was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $20$8 million primarily due to the following:
•A $12$13 million increase at PSO and SWEPCo primarily due to increased property taxes resulting fromand a new infrastructure fee at PSO implemented by the expirationCity of the Louisiana Industrial Tax Exemption related to Stall Plant.Tulsa in March 2022. This increase was partially offset in Retail Margins above.
•A $4 million increase at APCo primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
These increases were partially offset by:
•An $8 million decrease at I&M primarily due to property taxes driven by an increasethe repeal of the Indiana Utility Receipts Tax in utility plant.July 2022. This decrease was partially offset in Retail Margins above.
•Other Income increased $8$15 million primarily due to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.event at PSO and SWEPCo.
•Allowance for Equity Funds Used During Construction decreased $10 million primarily due to a decrease in AFUDC equity rates primarily at APCo.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $31 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $52 million primarily due to higher long-term debt balances at APCo, PSO and SWEPCo, increased Advances from Affiliates at SWEPCo, higher interest rates at APCo and a debt issuance at I&M in April 2021.
•Income Tax Expense decreased $7$45 million primarily due to athe following:
•An $81 million increase in PTCs. This increase was partially offset in Retail Margins above.
•A $7 million decrease in state income tax expense andtaxes.
These decreases were partially offset by:
•A $19 million increase due to an increase in PTC. This decrease was partially offset by apretax book income.
•A $14 million decrease in amortization of Excess ADIT, a decrease in parent company loss benefit and an increase in pretax book income.ADIT. The decrease in amortization of Excess ADIT iswas partially offset above in Retail Margins.Gross Margin above.
•A $14 million decrease in Parent Company Loss Benefit.
TRANSMISSION AND DISTRIBUTION UTILITIES
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
Transmission and Distribution Utilities | Transmission and Distribution Utilities | | 2021 | | 2020 | | 2021 | | 2020 | Transmission and Distribution Utilities | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
Revenues | Revenues | | $ | 1,200.3 | | | $ | 1,165.3 | | | $ | 3,391.8 | | | $ | 3,306.7 | | Revenues | | $ | 1,530.2 | | | $ | 1,200.3 | | | $ | 4,078.6 | | | $ | 3,391.8 | |
Purchased Electricity | Purchased Electricity | | 188.1 | | | 183.8 | | | 561.6 | | | 522.7 | | Purchased Electricity | | 399.5 | | | 188.1 | | | 884.8 | | | 561.6 | |
| Gross Margin | Gross Margin | | 1,012.2 | | | 981.5 | | | 2,830.2 | | | 2,784.0 | | Gross Margin | | 1,130.7 | | | 1,012.2 | | | 3,193.8 | | | 2,830.2 | |
Other Operation and Maintenance | Other Operation and Maintenance | | 442.6 | | | 439.1 | | | 1,168.6 | | | 1,158.2 | | Other Operation and Maintenance | | 503.6 | | | 442.6 | | | 1,373.2 | | | 1,168.6 | |
| Depreciation and Amortization | Depreciation and Amortization | | 164.6 | | | 163.5 | | | 515.8 | | | 585.0 | | Depreciation and Amortization | | 188.3 | | | 164.6 | | | 559.5 | | | 515.8 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 167.5 | | | 156.4 | | | 483.5 | | | 444.4 | | Taxes Other Than Income Taxes | | 176.7 | | | 167.5 | | | 504.9 | | | 483.5 | |
Operating Income | Operating Income | | 237.5 | | | 222.5 | | | 662.3 | | | 596.4 | | Operating Income | | 262.1 | | | 237.5 | | | 756.2 | | | 662.3 | |
Interest and Investment Income | | 0.4 | | | 0.9 | | | 1.1 | | | 2.0 | | |
Carrying Costs Income | | 0.1 | | | 0.3 | | | 1.1 | | | 1.3 | | |
| | Other Income | | Other Income | | 1.4 | | | 0.5 | | | 3.7 | | | 2.2 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 11.3 | | | 9.0 | | | 24.3 | | | 23.7 | | Allowance for Equity Funds Used During Construction | | 9.3 | | | 11.3 | | | 23.6 | | | 24.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 7.3 | | | 7.4 | | | 21.8 | | | 22.1 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 11.9 | | | 7.3 | | | 35.7 | | | 21.8 | |
Interest Expense | Interest Expense | | (77.3) | | | (74.0) | | | (228.8) | | | (217.6) | | Interest Expense | | (85.4) | | | (77.3) | | | (242.2) | | | (228.8) | |
Income Before Income Tax Expense | | 179.3 | | | 166.1 | | | 481.8 | | | 427.9 | | |
Income Before Income Tax Expense and Equity Earnings | | Income Before Income Tax Expense and Equity Earnings | | 199.3 | | | 179.3 | | | 577.0 | | | 481.8 | |
Income Tax Expense | Income Tax Expense | | 23.4 | | | 18.7 | | | 57.8 | | | 24.8 | | Income Tax Expense | | 33.8 | | | 23.4 | | | 94.7 | | | 57.8 | |
Equity Earnings of Unconsolidated Subsidiary | | Equity Earnings of Unconsolidated Subsidiary | | — | | | — | | | 0.8 | | | — | |
Net Income | Net Income | | 155.9 | | | 147.4 | | | 424.0 | | | 403.1 | | Net Income | | 165.5 | | | 155.9 | | | 483.1 | | | 424.0 | |
Net Income Attributable to Noncontrolling Interests | Net Income Attributable to Noncontrolling Interests | | — | | | — | | | — | | | — | | Net Income Attributable to Noncontrolling Interests | | — | | | — | | | — | | | — | |
Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | | $ | 155.9 | | | $ | 147.4 | | | $ | 424.0 | | | $ | 403.1 | | Earnings Attributable to AEP Common Shareholders | | $ | 165.5 | | | $ | 155.9 | | | $ | 483.1 | | | $ | 424.0 | |
Summary of KWh Energy Sales for Transmission and Distribution Utilities
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions of KWhs) | | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | | Retail: | | | | | | | | |
Residential | Residential | | 8,093 | | | 8,277 | | | 21,082 | | | 20,876 | | Residential | | 8,033 | | | 8,093 | | | 21,599 | | | 21,082 | |
Commercial | Commercial | | 7,125 | | | 6,722 | | | 19,189 | | | 18,154 | | Commercial | | 7,538 | | | 7,125 | | | 20,478 | | | 19,189 | |
Industrial | Industrial | | 6,048 | | | 5,417 | | | 17,667 | | | 16,473 | | Industrial | | 6,554 | | | 6,048 | | | 19,131 | | | 17,667 | |
Miscellaneous | Miscellaneous | | 207 | | | 206 | | | 558 | | | 568 | | Miscellaneous | | 210 | | | 207 | | | 578 | | | 558 | |
Total Retail (a) | Total Retail (a) | | 21,473 | | | 20,622 | | | 58,496 | | | 56,071 | | Total Retail (a) | | 22,335 | | | 21,473 | | | 61,786 | | | 58,496 | |
| Wholesale (b) | Wholesale (b) | | 644 | | | 502 | | | 1,692 | | | 1,347 | | Wholesale (b) | | 587 | | | 644 | | | 1,723 | | | 1,692 | |
| Total KWhs | Total KWhs | | 22,117 | | | 21,124 | | | 60,188 | | | 57,418 | | Total KWhs | | 22,922 | | | 22,117 | | | 63,509 | | | 60,188 | |
(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. 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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in degree days) | | | (in degree days) |
Eastern Region | Eastern Region | | | | | | | | | Eastern Region | | | | | | | | |
Actual – Heating (a) | Actual – Heating (a) | | 1 | | | 2 | | | 1,993 | | | 1,767 | | Actual – Heating (a) | | 8 | | | 1 | | | 2,078 | | | 1,993 | |
Normal – Heating (b) | Normal – Heating (b) | | 5 | | | 6 | | | 2,071 | | | 2,086 | | Normal – Heating (b) | | 5 | | | 5 | | | 2,077 | | | 2,071 | |
| Actual – Cooling (c) | Actual – Cooling (c) | | 787 | | | 809 | | | 1,148 | | | 1,126 | | Actual – Cooling (c) | | 755 | | | 787 | | | 1,115 | | | 1,148 | |
Normal – Cooling (b) | Normal – Cooling (b) | | 689 | | | 682 | | | 996 | | | 986 | | Normal – Cooling (b) | | 688 | | | 689 | | | 989 | | | 996 | |
| Western Region | Western Region | | | | | | | | | Western Region | | | | | | | | |
Actual – Heating (a) | Actual – Heating (a) | | — | | | 1 | | | 319 | | | 98 | | Actual – Heating (a) | | — | | | — | | | 278 | | | 319 | |
Normal – Heating (b) | Normal – Heating (b) | | — | | | — | | | 188 | | | 188 | | Normal – Heating (b) | | — | | | — | | | 193 | | | 188 | |
| Actual – Cooling (d) | Actual – Cooling (d) | | 1,308 | | | 1,357 | | | 2,278 | | | 2,524 | | Actual – Cooling (d) | | 1,478 | | | 1,308 | | | 2,701 | | | 2,278 | |
Normal – Cooling (b) | Normal – Cooling (b) | | 1,379 | | | 1,378 | | | 2,436 | | | 2,436 | | Normal – Cooling (b) | | 1,382 | | | 1,379 | | | 2,433 | | | 2,436 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 147.4155.9 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 45.174.9 | |
Margins from Off-system Sales | | (31.1)21.8 | |
Transmission Revenues | | 27.411.4 | |
Other Revenues | | (10.7)10.4 | |
Total Change in Gross Margin | | 30.7118.5 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (3.5)(61.0) | |
Depreciation and Amortization | | (1.1)(23.7) | |
| | |
Taxes Other Than Income Taxes | | (11.1)(9.2) | |
| | |
| | |
Interest and InvestmentOther Income | | (0.5) | |
Carrying Costs Income | | (0.2)0.9 | |
Allowance for Equity Funds Used During Construction | | 2.3 (2.0) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1)4.6 | |
Interest Expense | | (3.3)(8.1) | |
Total Change in Expenses and Other | | (17.5)(98.5) | |
| | |
Income Tax Expense | | (4.7)(10.4) | |
| | |
| | |
Third Quarter of 20212022 | | $ | 155.9165.5 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
•Retail Margins increased $45$75 million primarily due to the following:
•A $40$31 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.
•A $21 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 $22$7 million increase due to prior year refunds in Texas of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $15 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
•A $13 million increase from interim rate increases driven by increased distribution investment in Texas.
•A $3 million increase from interim rate increases driven by increased transmission investment in Texas.
•A $3 million increase in usage in Ohio primarily from the industrial and commercial class.
These increases were partially offset by:
•A $24 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 $15 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 $9 million decrease in weather-normalized margins in Texas primarily in the industrial class.
•A $3 million decrease in weather-related usage in Texas primarily due to a 4% decrease13% increase in cooling degree days.
•A $6 million increase in revenue from rate riders in Texas. This increase was partially offset in other expense items below.
•A $4 million increase in weather-related usage in Ohio primarily due to the end of decoupling.
•Margins from Off-system Sales decreased $31increased $22 million primarily due to the following:
•A $22$17 million decreaseincrease in Texas primarilyoff-system sales at OVEC in Ohio due to the retirement of the Oklaunion Power Station in September 2020.higher market prices. This decrease was partially offset in Depreciation and Amortization expenses below.
•A $19 million decrease in deferrals of OVEC costs in Ohio. This decreaseincrease was offset in Retail Margins above and Other Revenues below.
These decreases were partially offset by:
•A $10$5 million increase in off-system sales atdeferrals of OVEC costs in Ohio. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $27$11 million primarily due to the following:
•A $20 million increase from interim rate increases driven by increased transmission investment in Texas.
•
An $8 million increase due to prior year refunds to customers associated with the most recent base rate case in Texas. This increase was offset in Other Revenues below.
•Other Revenues decreased $11increased $10 million primarily due to the following:
•A $10$19 million decreaseincrease in securitization revenues primarily due to the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020.2020 and final refunds that were completed in 2021. This decreaseincrease was offset in Depreciation and Amortization expenses and Interest Expense below.
•An $8 million decrease due to prior year refunds to customers associated with the most recent base rate case in Texas. This decrease was partially offset in Retail Margins and Transmission Revenues above.
This decreaseincrease was partially offset by:
•An $8A $13 million increase primarilydecrease due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs in Ohio. This increasedecrease 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 Maintenance expenses increased $4$61 million primarily due to the following:
•A $34$21 million increase in PJMERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
•A $10$14 million increase in vegetation managementtransmission expenses in Ohio primarily due to an increase in recoverable PJM expenses. This increase was partially offset in Retail Margins above.
•A $10$6 million increase in distribution relateddistribution-related expenses due to increased maintenance, storms and billings.in Texas.
•A $3$5 million increase due to timing of AEPSC taxes.
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.
•A $16 million decrease in energy efficiency/demand side management expenses in Ohio. This decrease was partially offset in Retail Margins above.
•A $15 million decrease in remitted USFUniversal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decreaseincrease was offset in Retail Margins above.
•A $6$5 million decreaseincrease in employee-related expenses.recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
•Depreciation and Amortization expenses increased $1$24 million primarily due to the following:
•A $10$19 million increase in depreciation expense due to an increase in the depreciable base of transmission and distribution assets.
This increase was partially offset by:
•A $9 million decrease in securitization amortizations in Texas primarily relateddue to theprior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Other Revenues above.
•.A $6 million increase due to a higher depreciable base of transmission and distribution assets in Texas.
•A $4 million increase in recoverable advanced metering system depreciable expenses in Texas.
These increases were partially offset by:
•A $6 million decrease in recoverable Distribution Investment Rider depreciable expenses in Ohio. This decrease was offset in Other RevenuesRetail Margins above.
•Taxes Other Than Income Taxes increased $11$9 million primarily due to increased property taxes driven by additional investments inas a result of increased distribution and transmission and distribution assetsinvestment and higher tax rates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $5 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $3$8 million primarily due to the following:
•An $11 million increase in Texas primarily due to higher long-term debt balances.balances and higher interest rates.
This increase was partially offset by:
•A $3 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.
•Income Tax Expense increased $5$10 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. This increaseThe decrease in amortization of Excess ADIT was partially offset in Gross Margin above.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 403.1424.0 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 146.3290.0 | |
Margins from Off-system Sales | | (87.2)47.8 | |
Transmission Revenues | | 69.950.0 | |
Other Revenues | | (82.8)(24.2) | |
Total Change in Gross Margin | | 46.2363.6 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (10.4)(204.6) | |
Depreciation and Amortization | | 69.2 (43.7) | |
| | |
Taxes Other Than Income Taxes | | (39.1)(21.4) | |
| | |
| | |
Interest and InvestmentOther Income | | (0.9) | |
Carrying Costs Income | | (0.2)1.5 | |
Allowance for Equity Funds Used During Construction | | 0.6 (0.7) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3)13.9 | |
Interest Expense | | (11.2)(13.4) | |
Total Change in Expenses and Other | | 7.7 (268.4) | |
| | |
Income Tax Expense | | (33.0)(36.9) | |
Equity Earnings of Unconsolidated Subsidiary | | 0.8 | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 424.0483.1 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
•Retail Margins increased $146$290 million primarily due to the following:
•A $129An $85 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 $71$70 million increase due to interim rate increases driven by increased distribution and transmission investment in Texas.
•A $31 million increase due to prior year refunds of Excess ADIT to customers in Texas. This increase was offset in Income Tax Expense below.
•A $28 million increase in weather-normalized margins primarily from the commercial class.
•A $25 million increase related to various rider revenues in Ohio. This increase was partially offset in Margins from Off-system Sales, Other Revenues and other expense items below.
•A $34$20 million increase in revenue from interim rate increases driven by increased distribution investmentriders in Texas.
•An $18 million This increase from interim rate increases driven by increased transmission investmentwas partially offset in Texas.other expense items below.
•A $10$15 million increase in weather-related usage in Texas primarily due to a 226%19% increase in heatingcooling degree days, partially offset by a 10%13% decrease in coolingheating degree days.
These increases were partially offset by:
•A $71 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 $43 million decrease in revenues in Ohio associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.
•An $8 million decreaseincrease in weather-normalized marginsweather-related usage in TexasOhio primarily indue to the industrial class.end of decoupling.
•Margins from Off-system Sales decreased $87increased $48 million primarily due to the following:
•A $51$54 million decreaseincrease in Texas primarilyoff-system sales at OVEC in Ohio due to the retirement of the Oklaunion Power Station in September 2020.higher market prices and volume. This decreaseincrease was partially offset in DepreciationRetail Margins above and Amortization expensesOther Revenues below.
This increase was partially offset by:
•A $51$6 million decrease in deferrals of OVEC costs in Ohio. This decrease was offset in Retail Margins above and Other Revenues below.
These decreases were partially offset by:
•A $16 million increase in off-system sales at OVEC in Ohio. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues increased $70$50 million primarily due to the following:
•A $59$46 million increase fromdue to interim rate increases driven by increased transmission investment in Texas.
•A $14$7 million increase due to a prior year one-time creditrefunds to transmission customers in Texas as a result of Tax Reform andassociated with the most recent base rate case.case in Texas. This increase was offset in Income Tax ExpenseOther Revenues below.
•A $7 million increase due to continued investment in transmission assets in Ohio.
These increases were partially offset by:
•An $11 million decrease due to transmission formula rate true-up activity in Ohio.
•Other Revenues decreased $83$24 million primarily due to the following:
•A $104$29 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 in Depreciation and Amortization expenses and Interest Expense below.
This decrease was partially offset by:
•A $21 million increase in Ohio primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs.costs in Ohio. This increasedecrease was offset in Retail Margins and Margins from Off-system Sales above.
•A $12 million decrease due to prior year refunds to customers associated with the most recent base rate case in Texas. This decrease was partially offset in Retail Margins and Transmission Revenues above.
•A $5 million decrease in energy efficiency revenues in Texas.
These decreases were partially offset by:
•A $20 million increase in securitization revenues due to AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset in Depreciation and Amortization expenses and Interest Expense below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $10$205 million primarily due to the following:
•A $131$67 million increase in PJM transmission expenses includingin Ohio primarily due to the annual formula rate true-up. This increase was partially offset in Retail Margins above.following:
•A $16$67 million increase in vegetation managementrecoverable PJM expenses. This increase was offset in Retail Margins above.
•An $11A $6 million increase in distribution related expenses.
•A $7 million increase in stormtransmission vegetation management expenses.
These increases were partially offset by:
•A $47$10 million decrease in energy efficiency/demand side managementtransmission formula rate true-up activity.
•A $46 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Margins and Transmission Revenues above.
•A $20 million increase in employee-related expenses.
•A $19 million increase in bad debt-related expenses, including $8 million in 2022 due to Bad Debt Rider over-recovery in Ohio. This decreaseincrease was partially offset in Retail Margins above.
•A $43$15 million decreaseincrease in recoverable distribution expenses in Ohio primarily related to vegetation management. This increase was offset in Retail Margins above.
•A $14 million increase in remitted USFUniversal Services Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This decreaseincrease was offset in Retail Margins above.
•A $41$13 million decreaseincrease in Texas due to the Oklaunion Power Station retirementdistribution-related expenses in September 2020 and its sale to a nonaffiliated third-party in October 2020. This decrease was offset in Gross Margin above.
•A $19 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•A $5 million decrease in employee-related expenses.Texas.
•Depreciation and Amortization expenses decreased $69increased $44 million primarily due to the following:
•A $102$24 million decreaseincrease due to a higher depreciable base and amortizations of transmission and distribution assets in Texas.
•A $19 million increase in securitization amortizations in Texas primarily relateddue to theprior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. and final refunds that were completed in 2021. This decreaseincrease was offset in Other Revenues above.
•An $11 million increase in recoverable advanced metering system depreciable expenses in Texas.
These decreasesincreases were partially offset by:
•An $18A $6 million increasedecrease in depreciation expense due to an increaserecoverable smart grid depreciable expenses in the depreciable base of transmission and distribution assets.Ohio. This decrease was offset in Retail Margins above.
•
An $8 million increase in amortization of plant primarily related to capitalized software in Ohio.
•A $7$6 million increasedecrease in recoverable DIRDistribution Investment Rider depreciable expenseexpenses in Ohio. This increasedecrease was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $39$21 million primarily due to increased property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $14 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $11$13 million primarily due to the following:
•A $21 million increase in Texas primarily due to higher long-term debt balances.balances and higher interest rates.
This increase was partially offset by:
•
A $7 million decrease in Ohio primarily due to the retirement of a higher rate bond, partially offset by the issuance of a lower rate bond in 2021.•Income Tax Expense increased $33$37 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT and an increase in pretax book income, partially offset by favorable discrete adjustments recognized during the periods.ADIT. The decrease in amortization of Excess ADIT is partially offset in Gross Margin above.
AEP TRANSMISSION HOLDCO
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
AEP Transmission Holdco | AEP Transmission Holdco | | 2021 | | 2020 | | 2021 | | 2020 | AEP Transmission Holdco | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
Transmission Revenues | Transmission Revenues | | $ | 391.6 | | | $ | 317.9 | | | $ | 1,146.8 | | | $ | 877.8 | | Transmission Revenues | | $ | 430.9 | | | $ | 391.6 | | | $ | 1,221.1 | | | $ | 1,146.8 | |
Other Operation and Maintenance | Other Operation and Maintenance | | 40.3 | | | 30.1 | | | 96.9 | | | 85.9 | | Other Operation and Maintenance | | 46.5 | | | 40.3 | | | 114.4 | | | 96.9 | |
Depreciation and Amortization | Depreciation and Amortization | | 78.1 | | | 63.6 | | | 225.5 | | | 182.8 | | Depreciation and Amortization | | 89.5 | | | 78.1 | | | 262.7 | | | 225.5 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 62.7 | | | 53.8 | | | 183.4 | | | 157.5 | | Taxes Other Than Income Taxes | | 70.5 | | | 62.7 | | | 207.9 | | | 183.4 | |
Operating Income | Operating Income | | 210.5 | | | 170.4 | | | 641.0 | | | 451.6 | | Operating Income | | 224.4 | | | 210.5 | | | 636.1 | | | 641.0 | |
Interest and Investment Income | Interest and Investment Income | | 0.3 | | | 0.2 | | | 0.7 | | | 2.6 | | Interest and Investment Income | | 0.7 | | | 0.3 | | | 1.1 | | | 0.7 | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 16.1 | | | 20.3 | | | 49.3 | | | 54.9 | | Allowance for Equity Funds Used During Construction | | 20.3 | | | 16.1 | | | 51.2 | | | 49.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 0.5 | | | 0.5 | | | 1.6 | | | 1.5 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 1.3 | | | 0.5 | | | 3.8 | | | 1.6 | |
Interest Expense | Interest Expense | | (37.6) | | | (34.0) | | | (108.4) | | | (99.0) | | Interest Expense | | (44.4) | | | (37.6) | | | (124.2) | | | (108.4) | |
Income Before Income Tax Expense and Equity Earnings | Income Before Income Tax Expense and Equity Earnings | | 189.8 | | | 157.4 | | | 584.2 | | | 411.6 | | Income Before Income Tax Expense and Equity Earnings | | 202.3 | | | 189.8 | | | 568.0 | | | 584.2 | |
Income Tax Expense | Income Tax Expense | | 42.0 | | | 38.2 | | | 131.2 | | | 101.3 | | Income Tax Expense | | 52.1 | | | 42.0 | | | 141.9 | | | 131.2 | |
Equity Earnings of Unconsolidated Subsidiary | Equity Earnings of Unconsolidated Subsidiary | | 20.1 | | | 20.1 | | | 57.7 | | | 62.8 | | Equity Earnings of Unconsolidated Subsidiary | | 21.2 | | | 20.1 | | | 61.7 | | | 57.7 | |
Net Income | Net Income | | 167.9 | | | 139.3 | | | 510.7 | | | 373.1 | | Net Income | | 171.4 | | | 167.9 | | | 487.8 | | | 510.7 | |
Net Income Attributable to Noncontrolling Interests | Net Income Attributable to Noncontrolling Interests | | 1.1 | | | 1.0 | | | 3.2 | | | 2.7 | | Net Income Attributable to Noncontrolling Interests | | 0.9 | | | 1.1 | | | 2.4 | | | 3.2 | |
Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | | $ | 166.8 | | | $ | 138.3 | | | $ | 507.5 | | | $ | 370.4 | | Earnings Attributable to AEP Common Shareholders | | $ | 170.5 | | | $ | 166.8 | | | $ | 485.4 | | | $ | 507.5 | |
Summary of Investment in Transmission Assets for AEP Transmission Holdco
| | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Plant in Service | Plant in Service | | $ | 11,256.0 | | | $ | 9,644.6 | | Plant in Service | | $ | 12,455.2 | | | $ | 11,256.0 | |
Construction Work in Progress | Construction Work in Progress | | 1,609.6 | | | 1,732.5 | | Construction Work in Progress | | 1,752.7 | | | 1,609.6 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 758.1 | | | 553.1 | | Accumulated Depreciation and Amortization | | 986.3 | | | 758.1 | |
Total Transmission Property, Net | Total Transmission Property, Net | | $ | 12,107.5 | | | $ | 10,824.0 | | Total Transmission Property, Net | | $ | 13,221.6 | | | $ | 12,107.5 | |
Third Quarter of 20212022 Compared to Third Quarter of 20202021
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | | | | | | | |
Third Quarter of 20202021 | | $ | 138.3166.8 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 73.739.3 | |
Total Change in Transmission Revenues | | 73.739.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (10.2)(6.2) | |
Depreciation and Amortization | | (14.5)(11.4) | |
Taxes Other Than Income Taxes | | (8.9)(7.8) | |
Interest and Investment Income | | 0.10.4 | |
| | |
Allowance for Equity Funds Used During Construction | | (4.2)4.2 | |
Non-Service Cost Components of Net Periodic Pension Cost | | 0.8 | |
Interest Expense | | (3.6)(6.8) | |
Total Change in Expenses and Other | | (41.3)(26.8) | |
| | |
Income Tax Expense | | (3.8)(10.1) | |
Equity Earnings of Unconsolidated Subsidiary | | 1.1 | |
Net Income Attributable to Noncontrolling Interests | | (0.1)0.2 | |
| | |
Third Quarter of 20212022 | | $ | 166.8170.5 | |
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $74$39 million primarily due to continued investment in transmission assets.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $10$6 million primarily due to the following:
•A $2 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in employee-related expenses.
•A $1 million increase in rent expense.cancelled capital projects.
•Depreciation and Amortization expenses increased $15$11 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9$8 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreasedincreased $4 million primarily due to lowerhigher CWIP.
•Interest Expense increased $4$7 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $4$10 million primarily due to an increase in pretax book income partially offset by an increaseand a decrease in parent company loss benefit.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022
Earnings Attributable to AEP Common Shareholders from AEP Transmission Holdco
(in millions)
| | | | | | | | |
Nine Months Ended September 30, 20202021 | | $ | 370.4507.5 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 269.074.3 | |
Total Change in Transmission Revenues | | 269.074.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (11.0)(17.5) | |
Depreciation and Amortization | | (42.7)(37.2) | |
Taxes Other Than Income Taxes | | (25.9)(24.5) | |
Interest and Investment Income | | (1.9)0.4 | |
| | |
Allowance for Equity Funds Used During Construction | | (5.6)1.9 | |
Non-Service Cost Components of Net Periodic Pension Cost | | 0.12.2 | |
Interest Expense | | (9.4)(15.8) | |
Total Change in Expenses and Other | | (96.4)(90.5) | |
| | |
Income Tax Expense | | (29.9)(10.7) | |
Equity Earnings of Unconsolidated Subsidiary | | (5.1)4.0 | |
Net Income Attributable to Noncontrolling Interests | | (0.5)0.8 | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 507.5485.4 | |
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates, were as follows:
•Transmission Revenues increased $269$74 million primarily due to the following:
•A $206$117 million increase due to continued investment in transmission assets.
This increase was partially offset by:
•A $45$30 million increase as a result ofdecrease due to the affiliated annual transmission formula rate true-up which istrue-up. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
•A $16$13 million increase as a result ofdecrease due to the non-affiliatednonaffiliated annual transmission formula rate true-up.
Expenses and Other, Income Tax Expense and Equity Earnings of Unconsolidated Subsidiary changed between years as follows:
•Other Operation and Maintenance expenses increased $11$18 million primarily due to the following:
•A $4$15 million increase in vegetation managementemployee-related expenses.
•A $2$5 million increase in an accrual for NERC compliance costs.
•A $2 million increase in rent expense.
•A $1 million increase in property insurance premiums.due to cancelled capital projects.
•Depreciation and Amortization expenses increased $43$37 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $26$25 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreased $6 million primarily due to lower CWIP.
•Interest Expense increased $9$16 million primarily due to higher long-term debt balances.
•Income Tax Expenseincreased $30$11 million primarily due to an increasea decrease in parent company loss benefit, partially offset by a decrease in pretax book income.
•Equity Earnings of Unconsolidated Subsidiary decreased $5increased $4 million primarily due to higher pretax equity earnings for ETT, partially offset by lower pretax equity earnings at PATH-WV and ETT.for Pioneer.
GENERATION & MARKETING
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
Generation & Marketing | Generation & Marketing | | 2021 | | 2020 | | 2021 | | 2020 | Generation & Marketing | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
Revenues | Revenues | | $ | 621.1 | | | $ | 490.0 | | | $ | 1,691.9 | | | $ | 1,305.5 | | Revenues | | $ | 735.4 | | | $ | 621.1 | | | $ | 2,014.3 | | | $ | 1,691.9 | |
Fuel, Purchased Electricity and Other | Fuel, Purchased Electricity and Other | | 444.7 | | | 391.6 | | | 1,368.7 | | | 1,050.4 | | Fuel, Purchased Electricity and Other | | 566.1 | | | 444.7 | | | 1,534.0 | | | 1,368.7 | |
| Gross Margin | Gross Margin | | 176.4 | | | 98.4 | | | 323.2 | | | 255.1 | | Gross Margin | | 169.3 | | | 176.4 | | | 480.3 | | | 323.2 | |
Other Operation and Maintenance | Other Operation and Maintenance | | 38.2 | | | 27.2 | | | 98.8 | | | 85.1 | | Other Operation and Maintenance | | 44.7 | | | 38.2 | | | 71.2 | | | 98.8 | |
| Gain on Sale of Mineral Rights | | Gain on Sale of Mineral Rights | | — | | | — | | | (116.3) | | | — | |
Depreciation and Amortization | Depreciation and Amortization | | 21.1 | | | 18.5 | | | 59.7 | | | 54.1 | | Depreciation and Amortization | | 23.1 | | | 21.1 | | | 68.8 | | | 59.7 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 2.6 | | | 3.3 | | | 8.1 | | | 10.4 | | Taxes Other Than Income Taxes | | 3.1 | | | 2.6 | | | 9.3 | | | 8.1 | |
Operating Income | Operating Income | | 114.5 | | | 49.4 | | | 156.6 | | | 105.5 | | Operating Income | | 98.4 | | | 114.5 | | | 447.3 | | | 156.6 | |
Interest and Investment Income | Interest and Investment Income | | 1.3 | | | 0.4 | | | 2.4 | | | 2.6 | | Interest and Investment Income | | 12.5 | | | 1.3 | | | 21.4 | | | 2.4 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 3.8 | | | 3.9 | | | 11.5 | | | 11.6 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 5.1 | | | 3.8 | | | 15.4 | | | 11.5 | |
Interest Expense | Interest Expense | | (4.0) | | | (3.8) | | | (11.1) | | | (20.5) | | Interest Expense | | (16.7) | | | (4.0) | | | (30.7) | | | (11.1) | |
Income Before Income Tax Expense (Benefit) and Equity Earnings (Loss) | | 115.6 | | | 49.9 | | | 159.4 | | | 99.2 | | |
Income Before Income Tax Expense (Benefit) and Equity Loss | | Income Before Income Tax Expense (Benefit) and Equity Loss | | 99.3 | | | 115.6 | | | 453.4 | | | 159.4 | |
Income Tax Expense (Benefit) | Income Tax Expense (Benefit) | | 8.3 | | | (70.9) | | | (31.0) | | | (104.3) | | Income Tax Expense (Benefit) | | (5.1) | | | 8.3 | | | (25.3) | | | (31.0) | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (7.8) | | | (6.2) | | | (6.2) | | | 0.1 | | |
Equity Loss of Unconsolidated Subsidiaries | | Equity Loss of Unconsolidated Subsidiaries | | (8.2) | | | (7.8) | | | (200.6) | | | (6.2) | |
Net Income | Net Income | | 99.5 | | | 114.6 | | | 184.2 | | | 203.6 | | Net Income | | 96.2 | | | 99.5 | | | 278.1 | | | 184.2 | |
Net Loss Attributable to Noncontrolling Interests | Net Loss Attributable to Noncontrolling Interests | | (1.2) | | | (2.1) | | | (5.5) | | | (7.4) | | Net Loss Attributable to Noncontrolling Interests | | (1.3) | | | (1.2) | | | (6.2) | | | (5.5) | |
Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | | $ | 100.7 | | | $ | 116.7 | | | $ | 189.7 | | | $ | 211.0 | | Earnings Attributable to AEP Common Shareholders | | $ | 97.5 | | | $ | 100.7 | | | $ | 284.3 | | | $ | 189.7 | |
Summary of MWhs Generated for Generation & Marketing
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions of MWhs) | | | (in millions of MWhs) |
Fuel Type: | Fuel Type: | | | | | | | | | Fuel Type: | | | | | | | | |
Coal | Coal | | 1 | | | 1 | | | 3 | | | 3 | | Coal | | 1 | | | 1 | | | 3 | | | 3 | |
Renewables | Renewables | | 1 | | | — | | | 3 | | | 2 | | Renewables | | 1 | | | 1 | | | 3 | | | 3 | |
| Total MWhs | Total MWhs | | 2 | | | 1 | | | 6 | | | 5 | | Total MWhs | | 2 | | | 2 | | | 6 | | | 6 | |
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 116.7100.7 | |
| | |
Changes in Gross Margin: | | |
Merchant Generation | | (2.5)4.5 | |
Renewable Generation | | 8.919.2 | |
Retail, Trading and Marketing | | 71.6 (30.8) | |
Total Change in Gross Margin | | 78.0 (7.1) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (11.0)(6.5) | |
| | |
| | |
Depreciation and Amortization | | (2.6)(2.0) | |
Taxes Other Than Income Taxes | | 0.7 (0.5) | |
Interest and Investment Income | | 0.911.2 | |
| | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1)1.3 | |
Interest Expense | | (0.2)(12.7) | |
Total Change in Expenses and Other | | (12.3)(9.2) | |
| | |
Income Tax Expense | | (79.2)13.4 | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (1.6)(0.4) | |
Net LossIncome Attributable to Noncontrolling Interests | | (0.9)0.1 | |
| | |
Third Quarter of 2022 | | $ | 97.5 | |
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 $5 million primarily due to higher market prices.
•Renewable Generation increased $19 million primarily due to higher market prices at Texas wind facilities and new solar projects placed in service.
•Retail, Trading and Marketing decreased $31 million due to lower gains from mark-to-market economic hedging activity.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $7 million primarily due to the installment sale of Amazon substations in 2021.
•Interest and Investment Income increased $11 million primarily due to an increase in advances to affiliates.
•Interest Expense increased $13 million due to higher interest rates in 2022.
•Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income, an increase in PTCs and a decrease in state income taxes.
Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Nine Months Ended September 30, 2021 | | $ | 100.7189.7 | |
| | |
Changes in Gross Margin: | | |
Merchant Generation | | (6.1) | |
Renewable Generation | | 35.2 | |
Retail, Trading and Marketing | | 128.0 | |
Total Change in Gross Margin | | 157.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 27.6 | |
| | |
Gain on Sale of Mineral Rights | | 116.3 | |
Depreciation and Amortization | | (9.1) | |
Taxes Other Than Income Taxes | | (1.2) | |
Interest and Investment Income | | 19.0 | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 3.9 | |
Interest Expense | | (19.6) | |
Total Change in Expenses and Other | | 136.9 | |
| | |
Income Tax Benefit | | (5.7) | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (194.4) | |
Net Loss Attributable to Noncontrolling Interests | | 0.7 | |
| | |
Nine Months Ended September 30, 2022 | | $ | 284.3 | |
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, purchased electricity and certain cost of service for retail operations were as follows:
•Merchant Generation decreased $3$6 million primarily due to additional Cardinal plant outage days in 2022 and the retirementsale of Oklaunion Plant in 2020.Racine, partially offset by higher market prices.
•Renewable Generationincreased $9$35 million primarily due to higher market prices at Texas wind facilities and new solar and wind production.projects placed in service.
•Retail, Trading and Marketing increased $72$128 million due to higher mark-to-market economic hedge gainsactivity driven by higher commodity prices.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $11 million primarily due to the following:
•An $18 million increase due to gains recorded in 2020 on the sale of land.
This increase was partially offset by:
•A $7 million decrease in expenses related to the installment sale of Amazon substations and the retirement of Oklaunion Plant in 2020.
•Income Tax Expense increased $79 million primarily due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act, the impact of PTCs on the annualized effective tax rate and an increase in pretax book income.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021 |
Earnings Attributable to AEP Common Shareholders from Generation & Marketing |
(in millions) |
| | |
Nine Months Ended September 30, 2020 | | $ | 211.0 | |
| | |
Changes in Gross Margin: | | |
Merchant Generation | | 6.6 | |
Renewable Generation | | 17.2 | |
Retail, Trading and Marketing | | 44.3 | |
Total Change in Gross Margin | | 68.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (13.7) | |
| | |
| | |
Depreciation and Amortization | | (5.6) | |
Taxes Other Than Income Taxes | | 2.3 | |
Interest and Investment Income | | (0.2) | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1) | |
Interest Expense | | 9.4 | |
Total Change in Expenses and Other | | (7.9) | |
| | |
Income Tax Benefit | | (73.3) | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | (6.3) | |
Net Loss Attributable to Noncontrolling Interests | | (1.9) | |
| | |
Nine Months Ended September 30, 2021 | | $ | 189.7 | |
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 $7 million primarily due to higher market prices in PJM which drove increased generation at Cardinal Plant.
•Renewable Generation increased $17 million primarily due to increased solar and wind production.
•Retail, Trading and Marketing increased $44 million due to higher mark-to-market hedge gains driven by higher commodity prices. This increase was partially offset by 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 (Loss) of Unconsolidated Subsidiaries changed between years as follows:
•Other Operation and Maintenance expenses increased $14decreased $28 million primarily due to higher land sales and the following:sale of renewable development projects.
•A $20Gain on Sale of Mineral Rights increased $116 million increase from gains recorded in 2020 on the sale of land.
•A $17 million increase related to the Oklaunion PPA with AEP Texas primarily due to an ARO revision in 2020.
These increases were partially offset by:
•A $10 million decrease due to the retirement of Conesville Plant Unit 4 in 2020.
•A $5 million decrease due to a planned outage at Cardinal Plant in 2020.
•A $4 million decrease due to the retirement of Oklaunion Plant in 2020.
•A $4 million decrease due to the installmentcurrent year sale of Amazon substations.mineral rights.
•Depreciation and Amortization expenses increased $6$9 million due to a higher depreciable base from increased investments in renewable energy sources.assets.
•Interest and Investment Income increased $19 million primarily due to an increase in advances to affiliates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased$4 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $20 million due to higher interest rates in 2022.
•Interest Expense decreased $9 million due to lower borrowing costs in 2021.
•Income Tax Benefit decreased $73$6 million primarily due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act, the impact of PTCs on the annualized effective tax rate and an increase in pretax book income.income partially offset by an increase in PTCs and a favorable discrete tax adjustment in 2022.
•Equity Earnings (Loss) of Unconsolidated Subsidiaries decreased $6$194 million primarily due to lower revenues due to lower wind production from jointly owned assets.the impairment of AEP’s investment in Flat Ridge 2 Wind LLC.
CORPORATE AND OTHER
Third Quarter of 20212022 Compared to Third Quarter of 20202021
Earnings Attributable to AEP Common Shareholders from Corporate and Other decreased from a loss of $47$65 million in 20202021 to a loss of $65$227 million in 20212022 primarily due to:
•A $26$195 million unrealizedpretax loss from an investment in ChargePoint.related to the anticipated sale of Kentucky operations.
•A $6$35 million decreaseincrease in interest incomeexpense due to a lower returnhigher interest rates on investments held by EISshort-term debt, an increase in advances from affiliates and lower interest income from affiliates.an increase in long-term debt outstanding.
These items were partially offset by:
•A $9$28 million increase due to favorable changes in gains and losses from AEP’s investment in ChargePoint. As of August 2022, AEP no longer has a direct investment in ChargePoint.
•A $56 million decrease in Income Tax Expense primarily due to lower pretax book income andthe following:
•A $45 million decrease due to a loss on the anticipated sale of Kentucky operations.
•A $15 million decrease due to a change in the consolidated tax adjustment.Parent Company Loss Benefit.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
Earnings Attributable to AEP Common Shareholders from Corporate and Other increaseddecreased from a loss of $115 million in 2020 to a loss of $108 million in 2021 to a loss of $406 million in 2022 primarily due to:
•A $23$263 million increase in equity earnings from unrealized investment gains.pretax loss related to the anticipated sale of Kentucky operations.
•A $16$54 million decreaseincrease in interest expense.expense due to higher long-term debt outstanding and higher interest rates on short-term debt.
•A $12$45 million gaindecrease at EIS, primarily due to lower returns on investments and an increase in reserves.
•A $24 million decrease in equity earnings.
•A $22 million decrease due to unfavorable changes in gains and losses from anAEP’s investment in ChargePoint,ChargePoint. As of which $7 million is unrealized.August 2022, AEP no longer has a direct investment in ChargePoint.
These items were partially offset by:
•A $21$103 million decrease in interest incomeIncome Tax Expense primarily due to lower interest income from affiliates.the following:
•A $12$45 million increase indecrease due to a loss on the EIS reserve.
•An $8 million increase in general corporate expenses.anticipated sale of Kentucky operations.
•A $6$29 million increasedecrease due to a change in estimated health care benefits for certain retirees.pretax book income.
•A $33 million decrease due to Parent Company Loss Benefit.
AEP SYSTEM INCOME TAXES
Third Quarter of 20212022 Compared to Third Quarter of 20202021
Income Tax Expense increased $71decreased $86 million primarily due to the following:
•A $52 million increase due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act.
•A $25 million increase due to an increase in pretax book income.
•An $8 million increase due tobenefit from PTCs and a decrease in amortization of Excess ADIT.
These increases were partially offset by:
•A $15 million decrease in state income tax expense.pretax book income.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
Income Tax Expense increased $128decreased $95 million primarily due to the following:to:
•A $66$73 million increasedecrease due to an increase in PTCs.
•A $25 million decrease due to a decrease in pretax book income.
•A $52$26 million increasedecrease due to the recognition of a discrete tax adjustment in 2020 attributable to the CARES Act.
•A $19 million increase due toadjustments, primarily driven by the remeasurement of deferred state incomedeferred taxes as a result of legislative changesnewly enacted West Virginia and Oklahoma state legislation in 2021.
These increasesdecreases were partially offset by:
•A $23$33 million increase due to a decrease in PTC.
amortization of Excess ADIT.
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
| | | September 30, 2021 | | December 31, 2020 | | September 30, 2022 | | December 31, 2021 |
| | (dollars in millions) | | (dollars in millions) |
Long-term Debt, including amounts due within one year(a) | Long-term Debt, including amounts due within one year(a) | $ | 34,578.3 | | | 58.0 | % | | $ | 31,072.5 | | | 57.2 | % | Long-term Debt, including amounts due within one year(a) | $ | 35,050.1 | | | 56.3 | % | | $ | 33,454.5 | | | 57.0 | % |
Short-term Debt | Short-term Debt | 2,504.0 | | | 4.2 | | | 2,479.3 | | | 4.6 | | Short-term Debt | 2,702.3 | | | 4.3 | | | 2,614.0 | | | 4.4 | |
Total Debt | Total Debt | 37,082.3 | | | 62.2 | | | 33,551.8 | | | 61.8 | | Total Debt | 37,752.4 | | | 60.6 | | | 36,068.5 | | | 61.4 | |
AEP Common Equity | AEP Common Equity | 22,278.1 | | | 37.4 | | | 20,550.9 | | | 37.8 | | AEP Common Equity | 24,278.2 | | | 39.0 | | | 22,433.2 | | | 38.2 | |
Noncontrolling Interests | Noncontrolling Interests | 249.1 | | | 0.4 | | | 223.6 | | | 0.4 | | Noncontrolling Interests | 234.1 | | | 0.4 | | | 247.0 | | | 0.4 | |
Total Debt and Equity Capitalization | Total Debt and Equity Capitalization | $ | 59,609.5 | | | 100.0 | % | | $ | 54,326.3 | | | 100.0 | % | Total Debt and Equity Capitalization | $ | 62,264.7 | | | 100.0 | % | | $ | 58,748.7 | | | 100.0 | % |
(a)Amount excludes $1.2 billion and $1.1 billion as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
AEP’s ratio of debt-to-total capital increaseddecreased from 61.8%61.4% as of December 31, 20202021 to 62.2%60.6% as of September 30, 20212022 primarily due to the settlement of the forward equity purchase contracts related to the 2019 Equity Units, partially offset by an increase in debt to help address the cash flow implications resulting from the February 2021 severe winter weather event in addition to supportingsupport distribution, transmission and renewable investment growth. See “Equity Units” section of Note 12 for additional information.
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.liquidity. As of September 30, 2021,2022, 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. AEP and its utilities finance its operations with commercial paper and other variable rate instruments that are subject to fluctuations in interest rates. To the extent that the Federal Reserve continues to raise short-term interest rates, it could reduce future net income and cash flows and impact financial condition. In February 2021, severe winter weather impacted certain AEP service territories resulting in disruptions to SPP market conditions. See Note 4 - Rate Matters for additional information. In March 2021, AEP entered into a $500 million 364-day Term Loan and borrowed the full amount to help address the cash flow implications resulting from the February 2021 severe winter weather event. In March 2022, AEP extended the maturity date of the original 364-Day Term Loan to August 2022. In August 2022, AEP paid off the $500 million Term Loan. In 2022, increased fuel and purchased power prices continue to lead to an increase in under collection of fuel costs. As a result, in July 2022, APCo and KPCo entered into term loans of $100 million and $75 million, respectively, to help address the cash flow implications of the increased fuel and purchased power costs. See “Deferred Fuel Costs” section of Executive Overview for additional information on how the registrants are addressing the increase in deferred fuel regulatory assets. In September 2022, the ODFA issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for $687 million of extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event. See Note 4 - Rate Matters for additional information.
Net Available Liquidity
AEP manages liquidity by maintaining adequate external financing commitments. As of September 30, 2021,2022, available liquidity was approximately $5.1$3.6 billion as illustrated in the table below:
| | | | | | | | | | | | | | | | | |
| | Amount | | Maturity | |
Commercial Paper Backup: | (in millions) | | | |
| Revolving Credit Facility | $ | 4,000.0 | | | March 20262027 | (a) |
| Revolving Credit Facility | 1,000.0 | | | March 20232024 | (a) |
| 364-Day Term Loan | 500.0 | | | March 2022 | | |
| | | | | |
Cash and Cash Equivalents | 1,372.7522.2 | | | | |
Total Liquidity Sources | 6,872.75,522.2 | | | | |
Less: | AEP Commercial Paper Outstanding | 1,254.01,952.3 | | | | |
| 364-Day Term Loan | 500.0 | | | | | |
| | | | | |
| | | | | |
| | | | | |
Net Available Liquidity | $ | 5,118.73,569.9 | | | | |
(a)In April 2022, AEP extended the maturity dates of the Revolving Credit Facilities from March 2026 to March 2027 and from March 2023 to March 2024, respectively.
AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program funds a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and the short-term debt requirements of subsidiaries that are not participating in either money pool for regulatory or operational reasons, as direct borrowers. The maximum amount of commercial paper outstanding during the first nine months of 20212022 was $2.5$2.4 billion. The weighted-average interest rate for AEP’s commercial paper during 20212022 was 0.24%1.82%.
Other Credit Facilities
An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of subsidiaries under five uncommitted facilities totaling $375$400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20212022 was $180$310 million with maturities ranging from October 20212022 to August 2022.2023.
Securitized Accounts Receivables
AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility which expirewas renewed in September 20232022 and 2024, respectively.amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of September 30, 2021,2022, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.
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 September 30, 2021,2022, this contractually-defined percentage was 59.3%57.7%. 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)ATM Program
AEP participates in an ATM offering program that allows AEP to issue, from time to time, up to an aggregate of $1 billion of its common stock, including shares of common stock that may be sold pursuant to an equity forward sales agreement. There were no issuances under the ATM program for the nine months ended September 30, 2022. As of September 30, 2021,2022, approximately $534$511 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.
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 settlessettled after three years in 2022. The proceeds from this issuance were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC. In January 2022, AEP successfully remarketed the notes on behalf of holders of the corporate units and did not directly receive any proceeds therefrom. Instead, the holders of the corporate units used the debt remarketing proceeds to settle the forward equity purchase contract with AEP. The interest rate on the notes was reset to 2.031% with the maturity remaining in 2024. In March 2022, AEP issued 8,970,920 shares of AEP common stock and received proceeds totaling $805 million under the settlement of the forward equity purchase contract. AEP common stock held in treasury was used to settle the forward equity purchase contract.
See Note 12 - Financing Activities for additional information.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.78$0.83 per share in October 2021, a $0.04 per share increase as compared to the quarterly dividend declared in July 2021.2022. 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.
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.
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $ | 438.3 | | | $ | 432.6 | | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | $ | 451.4 | | | $ | 438.3 | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | 2,973.0 | | | 2,922.2 | | Net Cash Flows from Operating Activities | 4,733.2 | | | 2,973.0 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | (4,906.2) | | | (4,707.3) | | Net Cash Flows Used for Investing Activities | (5,822.5) | | | (4,906.2) | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | 2,921.6 | | | 1,816.3 | | Net Cash Flows from Financing Activities | 1,215.2 | | | 2,921.6 | |
| Net Increase in Cash and Cash Equivalents | Net Increase in Cash and Cash Equivalents | 988.4 | | | 31.2 | | Net Increase in Cash and Cash Equivalents | 125.9 | | | 988.4 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 1,426.7 | | | $ | 463.8 | | Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 577.3 | | | $ | 1,426.7 | |
Operating Activities
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Net Income | Net Income | $ | 1,949.5 | | | $ | 1,762.0 | | Net Income | $ | 1,922.2 | | | $ | 1,949.5 | |
Non-Cash Adjustments to Net Income (a) | Non-Cash Adjustments to Net Income (a) | 2,353.8 | | | 2,196.7 | | Non-Cash Adjustments to Net Income (a) | 2,661.1 | | | 2,191.1 | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | 101.0 | | | 46.4 | | Mark-to-Market of Risk Management Contracts | 162.3 | | | 101.0 | |
Pension Contributions to Qualified Plan Trust | — | | | (110.3) | | |
| Property Taxes | Property Taxes | 415.1 | | | 396.9 | | Property Taxes | 459.9 | | | 415.1 | |
Deferred Fuel Over/Under-Recovery, Net | Deferred Fuel Over/Under-Recovery, Net | (1,356.8) | | | 27.4 | | Deferred Fuel Over/Under-Recovery, Net | (148.7) | | | (1,356.8) | |
| Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | (270.7) | | | (322.0) | | Change in Other Noncurrent Assets | (6.0) | | | (108.0) | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | 162.7 | | | (25.1) | | Change in Other Noncurrent Liabilities | 324.0 | | | 162.7 | |
Change in Certain Components of Working Capital | Change in Certain Components of Working Capital | (381.6) | | | (1,049.8) | | Change in Certain Components of Working Capital | (641.6) | | | (381.6) | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | $ | 2,973.0 | | | $ | 2,922.2 | | Net Cash Flows from Operating Activities | $ | 4,733.2 | | | $ | 2,973.0 | |
(a)Non-Cash Adjustments to Net Income includes Depreciation and Amortization, Rockport Plant, Unit 2 Operating Lease Amortization, Deferred Income Taxes, Loss on the Expected Sale of the Kentucky Operations, Asset Impairments and Other Related Charges, Impairment of Equity Method Investment, AFUDC, Gain on Sale of Mineral Rights and AmortizationEstablishment of Nuclear Fuel.2017-2019 Virginia Triennial Review Regulatory Asset.
Net Cash Flows from Operating Activities increased by $51 million$1.8 billion primarily due to the following:
•A $668 million$1.2 billion increase in cash from the Change in Certain Components of Working Capital. The increase is primarily due to the timing of accounts receivablesfuel and payablespurchase power revenues and a decreaseexpenses. PSO and SWEPCo were impacted by the February 2021 severe winter weather event in SPP which led to significantly higher fuel material and supplies balances primarily due to decreasespurchased power expenses which were deferred as regulatory assets in coal2021. In September 2022, the ODFA issued ratepayer-backed securitization bonds and lignite inventory on hand.provided PSO proceeds of $687 million as reimbursement of the extraordinary fuel costs and purchased electricity incurred during the severe winter weather event. See Note 4 - Rate Matters for additional information. In 2022, increased fuel and purchased power prices in excess of amounts included in fuel-related revenues has resulted in an increase in the under collection of fuel costs in most jurisdictions, offsetting the proceeds received by PSO in September 2022. See the “Deferred Fuel Costs” section of Executive Overview for additional information.
•A $345$443 million increase in cash from Net Income, after non-cash adjustments. See Results of Operations for further detail.
•A $188$161 million increase in cash from the 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 $110$102 million increase in cash due to a discretionary contribution tofrom the qualified pension plan madeChange in the prior year. See Note 7 for additional information.
These increases in cash were partially offset by:
•A $1.4 billion decrease in cashOther Noncurrent Assets 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 $142 million decrease in cash due to incremental other operation and maintenance storm restoration expenses incurred in 2021 by APCo, SWEPCo and KPCo as a result of the February 2021 severe winter weather event. These incremental expenses have been deferred as regulatory assets. KPCo intends to seek recovery of these incremental storm restoration costs in theirits next base rate case while APCo is expected to seek recovery in separateeither upcoming rider or base case filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. The increase due to the February 2021 severe winter weather event was partially offset by the deferral of incremental other operation and maintenance storm restoration expenses incurred in June 2022 by APCo, KPCo, OPCo and WPCo. Recovery of the June 2022 storm costs will be requested in future filings. See Note 4 - Rate Matters for additional information.
These increases in cash were partially offset by:
•A $260 million decrease in cash from the Change in Certain Components of Working Capital. The decrease is primarily due to fuel, material and supplies driven by prior year decreases in coal and lignite inventory on hand, an increase in estimated federal income taxes paid and the timing of accounts receivables. These decreases were partially offset by the timing of accounts payable and a return of margin deposits from PJM originally paid in 2021.
Investing Activities
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Construction Expenditures | Construction Expenditures | $ | (4,087.0) | | | $ | (4,690.4) | | Construction Expenditures | $ | (4,748.5) | | | $ | (4,087.0) | |
Acquisitions of Nuclear Fuel | Acquisitions of Nuclear Fuel | (63.2) | | | (68.4) | | Acquisitions of Nuclear Fuel | (91.9) | | | (63.2) | |
| Acquisition of the Dry Lake Solar Project | | Acquisition of the Dry Lake Solar Project | — | | | (114.4) | |
Acquisition of the North Central Wind Energy Facilities | Acquisition of the North Central Wind Energy Facilities | (652.8) | | | — | | Acquisition of the North Central Wind Energy Facilities | (1,207.3) | | | (652.8) | |
Acquisition of the Dry Lake Solar Project | (114.4) | | | — | | |
Proceeds from Sale of Assets | | Proceeds from Sale of Assets | 215.7 | | | 17.4 | |
Other | Other | 11.2 | | | 51.5 | | Other | 9.5 | | | (6.2) | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | $ | (4,906.2) | | | $ | (4,707.3) | | Net Cash Flows Used for Investing Activities | $ | (5,822.5) | | | $ | (4,906.2) | |
Net Cash Flows Used for Investing Activities increased by $199$916 million primarily due to the following:
•A $767$662 million increase in Construction Expenditures, primarily due to increases in Vertically Integrated Utilities of $437 million and Transmission and Distribution Utilities of $271 million.
•A $440 million increase due to the 2022 acquisition of Traverse, partially offset by the North Central Wind Energy Facilities and2021 acquisitions of the Dry Lake Solar Project.Project and Sundance. See Note 6 - Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments for additional information.
This increaseThese increases in the use of cash wasused were partially offset by:
•A $603$198 million decreaseincrease in construction expenditures,Proceeds from Sale of Assets, primarily due to decreases in Transmissionthe sale of certain mineral rights. See Note 6 - Acquisitions, Assets and Distribution Utilities of $302 million, Vertically Integrated Utilities of $136 millionLiabilities Held for Sale, Dispositions and AEP Transmission Holdco of $76 million.Impairments for additional information.
Financing Activities
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Issuance of Common Stock | Issuance of Common Stock | $ | 548.0 | | | $ | 136.5 | | Issuance of Common Stock | $ | 827.2 | | | $ | 548.0 | |
Issuance/Retirement of Debt, Net | Issuance/Retirement of Debt, Net | 3,537.2 | | | 2,844.0 | | Issuance/Retirement of Debt, Net | 1,837.6 | | | 3,537.2 | |
| Dividends Paid on Common Stock | Dividends Paid on Common Stock | (1,122.7) | | | (1,055.7) | | Dividends Paid on Common Stock | (1,212.5) | | | (1,122.7) | |
Other | Other | (40.9) | | | (108.5) | | Other | (237.1) | | | (40.9) | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | $ | 2,921.6 | | | $ | 1,816.3 | | Net Cash Flows from Financing Activities | $ | 1,215.2 | | | $ | 2,921.6 | |
Net Cash Flows from Financing Activities increaseddecreased by $1.1$1.7 billion primarily due to the following:
•A $1.1$1.6 billion increasedecrease in issuances of long-term debt. See Note 12 - Financing Activities for additional information.
•A $466$129 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
These decreases in cash were partially offset by:
•A $279 million increase in issuances of common stock primarily due to the settlement of the 2019 equity units. See “Equity Units” section of Note 12 for additional information.
•A $64 million increase due to changes in short-term debt. See Note 12 - Financing Activities for additional information.
•A $412 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:
•An $849 million increase in retirements of long-term debt. See Note 12 - Financing Activities for additional information.
See the “Long-term Debt Subsequent Events” section of Note 12 for Long-term debt and other securities issued, retired and principal payments made after September 30, 20212022 through October 28, 2021,27, 2022, the date that the third quarter 10-Q was issued.filed.
BUDGETED CAPITAL EXPENDITURES
Management forecasts approximately $6.9$7.6 billion of capital expenditures in 2021.2022. For the four year period, 20222023 through 2025,2026, management forecasts capital expenditures of $30.4$32.9 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, supply chain issues, weather, legal reviews, inflation and the ability to access capital. Management expects to fund these capital expenditures through cash flows from operations, proceeds from the sale of Kentucky operations, proceeds from the sale of competitive contracted renewables and financing activities. Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. 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 20202021 Annual Report.
CONTRACTUAL OBLIGATION INFORMATIONSIGNIFICANT CASH REQUIREMENTS
A summary of contractual obligationssignificant cash requirements is included in the 20202021 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 20202021 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.
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 OperationsRegulated 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 President & 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 President & Chief Financial Officer, Senior Vice President of Treasury and Risk and Chief Risk Officer in addition to Energy Supply’s PresidentChief Commercial Officer and Senior Vice President.President of Financial and Commercial Operations. 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 hashad a large outstanding unpaid balance associated with the February 2021 winter storm. Socialized lossesA certain portion of this balance has been securitized and disbursed to impacted market participants. A recovery plan has been reached by ERCOT for the remaining portion of the outstanding balance. In both cases, financial costs are allocated to load serving entities through their qualified scheduling entitiescertain market participants and in thatthe 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.
The following table summarizes the reasons for changes in total MTM value as compared to December 31, 2020:2021:
| MTM Risk Management Contract Net Assets (Liabilities) | MTM Risk Management Contract Net Assets (Liabilities) | MTM Risk Management Contract Net Assets (Liabilities) |
Nine Months Ended September 30, 2021 | |
Nine Months Ended September 30, 2022 | | Nine Months Ended September 30, 2022 |
| | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | Generation & Marketing | | Total |
| | (in millions) | | (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 | (20.4) | | | (5.6) | | | (11.9) | | | (37.9) | | |
Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021 | | Total MTM Risk Management Contract Net Assets (Liabilities) as of December 31, 2021 | $ | 59.8 | | | $ | (91.4) | | | $ | 275.9 | | | $ | 244.3 | |
(Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | (Gain)/Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | (65.5) | | | 3.7 | | | (50.0) | | | (111.8) | |
Fair Value of New Contracts at Inception When Entered During the Period (a) | Fair Value of New Contracts at Inception When Entered During the Period (a) | — | | | — | | | 1.0 | | | 1.0 | | Fair Value of New Contracts at Inception When Entered During the Period (a) | — | | | — | | | 0.9 | | | 0.9 | |
| Changes in Fair Value Due to Market Fluctuations During the Period (b) | Changes in Fair Value Due to Market Fluctuations During the Period (b) | — | | | — | | | 138.1 | | | 138.1 | | Changes in Fair Value Due to Market Fluctuations During the Period (b) | 1.9 | | | — | | | 265.4 | | | 267.3 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 46.3 | | | 26.4 | | | — | | | 72.7 | | Changes in Fair Value Allocated to Regulated Jurisdictions (c) | 224.5 | | | 44.6 | | | — | | | 269.1 | |
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2021 | $ | 67.1 | | | $ | (88.7) | | | $ | 295.3 | | | 273.7 | | |
MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d) | | MTM Risk Management Contract Net Assets Held for Sale Related to KPCo (d) | (8.4) | | | — | | | — | | | (8.4) | |
Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2022 | | Total MTM Risk Management Contract Net Assets (Liabilities) as of September 30, 2022 | $ | 212.3 | | | $ | (43.1) | | | $ | 492.2 | | | 661.4 | |
Commodity Cash Flow Hedge Contracts | Commodity Cash Flow Hedge Contracts | | | | | | | 359.5 | | Commodity Cash Flow Hedge Contracts | | | | | | | 572.7 | |
Interest Rate Cash Flow Hedge Contracts | Interest Rate Cash Flow Hedge Contracts | | | | | | 4.9 | | Interest Rate Cash Flow Hedge Contracts | | | | | | 8.8 | |
Fair Value Hedge Contracts | Fair Value Hedge Contracts | | | | | | (25.4) | | Fair Value Hedge Contracts | | | | | | (135.4) | |
Collateral Deposits | Collateral Deposits | | | | | | (271.3) | | Collateral Deposits | | | | | | (847.0) | |
| Total MTM Derivative Contract Net Assets as of September 30, 2021 | | | | | | $ | 341.4 | | |
Total MTM Derivative Contract Net Assets as of September 30, 2022 | | Total MTM Derivative Contract Net Assets as of September 30, 2022 | | | | | | $ | 260.5 | |
(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.payable on the balance sheet.
(d)MTM risk management contract net assets relating to KPCo are classified as Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
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 September 30, 2021,2022, credit exposure net of collateral to sub investment grade counterparties was approximately 1.8%0.8%, 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).
As of September 30, 2021,2022, the following table approximates AEP’s counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
| Counterparty Credit Quality | Counterparty Credit Quality | | Exposure Before Credit Collateral | | Credit Collateral | | Net Exposure | | Number of Counterparties >10% of Net Exposure | | Net Exposure of Counterparties >10% | 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) | | | (in millions, except number of counterparties) |
Investment Grade | Investment Grade | | $ | 505.7 | | | $ | 33.6 | | | $ | 472.1 | | | 3 | | | $ | 199.3 | | Investment Grade | | $ | 830.1 | | | $ | 399.5 | | | $ | 430.6 | | | 3 | | | $ | 186.4 | |
| Split Rating | | Split Rating | | 0.8 | | | — | | | 0.8 | | | 1 | | | 0.8 | |
Noninvestment Grade | | Noninvestment Grade | | 2.5 | | | 2.4 | | | 0.1 | | | 1 | | | 0.1 | |
No External Ratings: | No External Ratings: | | | | | | | | | No External Ratings: | | | | | | | | |
Internal Investment Grade | Internal Investment Grade | | 80.4 | | | — | | | 80.4 | | | 3 | | | 61.9 | | Internal Investment Grade | | 32.1 | | | — | | | 32.1 | | | 3 | | | 24.7 | |
Internal Noninvestment Grade | Internal Noninvestment Grade | | 14.2 | | | 4.2 | | | 10.0 | | | 2 | | | 5.8 | | Internal Noninvestment Grade | | 16.7 | | | 13.2 | | | 3.5 | | | 4 | | | 3.4 | |
Total as of September 30, 2021 | | $ | 600.3 | | | $ | 37.8 | | | $ | 562.5 | | | |
Total as of September 30, 2022 | | Total as of September 30, 2022 | | $ | 882.2 | | | $ | 415.1 | | | $ | 467.1 | | |
All exposure in the table above relates to AEPSC and AEPEP as AEPSC is agent for and transacts on behalf of certain AEP subsidiaries, including the Registrant Subsidiaries and AEPEP is agent for and transacts on behalf of other AEP subsidiaries.
In addition, AEP is exposed to credit risk related to participation in RTOs. For each of the RTOs in which AEP participates, this risk is generally determined based on the proportionate share of member gross activity over a specified period of time.
Value at Risk (VaR) Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates VaR, to measure AEP’s commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2021,2022, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.
Management calculates the VaR for both a trading and non-trading portfolio. The trading portfolio consists primarily of contracts related to energy trading and marketing activities. The non-trading portfolio consists primarily of economic hedges of generation and retail supply activities.
The following tables show the end, high, average and low market risk as measured by VaR for the periods indicated:
VaR Model
Trading Portfolio
| Nine Months Ended | Nine Months Ended | | Twelve Months Ended | Nine Months Ended | | Twelve Months Ended |
September 30, 2021 | | December 31, 2020 | |
September 30, 2022 | | September 30, 2022 | | December 31, 2021 |
End | End | | High | | Average | | Low | | End | | High | | Average | | Low | End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | (in millions) | | (in millions) | (in millions) | | (in millions) |
$ | 1.7 | | | $ | 3.6 | | | $ | 0.3 | | | $ | 0.1 | | | $ | 0.1 | | | $ | 0.3 | | | $ | 0.1 | | | $ | — | | 0.4 | | | $ | 4.5 | | | $ | 0.8 | | | $ | 0.1 | | | $ | 0.4 | | | $ | 3.6 | | | $ | 0.4 | | | $ | 0.1 | |
VaR Model
Non-Trading Portfolio
| Nine Months Ended | Nine Months Ended | | Twelve Months Ended | Nine Months Ended | | Twelve Months Ended |
September 30, 2021 | | December 31, 2020 | |
September 30, 2022 | | September 30, 2022 | | December 31, 2021 |
End | End | | High | | Average | | Low | | End | | High | | Average | | Low | End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | (in millions) | | (in millions) | (in millions) | | (in millions) |
$ | 7.7 | | | $ | 7.8 | | | $ | 2.3 | | | $ | 0.7 | | | $ | 2.2 | | | $ | 2.9 | | | $ | 1.0 | | | $ | 0.1 | | 16.6 | | | $ | 76.9 | | | $ | 26.0 | | | $ | 6.7 | | | $ | 8.3 | | | $ | 14.9 | | | $ | 3.7 | | | $ | 0.7 | |
Management back-tests VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As the VaR calculation captures recent price movements, management also performs regular stress testing of the trading portfolio to understand AEP’s exposure to extreme price movements. A historical-based method is employed whereby the current trading portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee, Regulated Risk Committee or Competitive Risk Committee as appropriate.
Interest Rate Risk
AEP is exposed to interest rate market fluctuations in the normal course of business operations. Recently, interest rates have remained at relatively low levels on a historical basis and the Federal Reserve maintained the federal funds target range at 0.0% to 0.25% for much of 2021. However, in March 2022, the Federal Reserve approved a 0.25% rate increase and in each of June, July and September of 2022 approved further 0.75% rate increases. The Federal Reserve has indicated that, in light of increasing signs of inflation, it foresees further increases in interest rates throughout the year and into 2023 and 2024. AEP has outstanding short and long-term debt which is subject to a variable rate.rates. AEP manages interest rate risk by limiting variable-rate exposures to a percentage of total debt, by entering into interest rate derivative instruments and by monitoring the effects of market changes in interest rates. For the nine months ended September 30, 20212022 and 2020,2021, a 100 basis point change in the benchmark rate on AEP’s variable rate debt would impact pretax interest expense annually by $32$47 million and $18$32 million, respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions, except per-share and share amounts)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | Nine Months Ended |
| | Three Months Ended | | Nine Months Ended | | September 30, | | September 30, |
| | September 30, | | September 30, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Vertically Integrated Utilities | Vertically Integrated Utilities | | $ | 2,716.8 | | | $ | 2,400.1 | | | $ | 7,445.9 | | | $ | 6,655.4 | | Vertically Integrated Utilities | | $ | 3,174.6 | | | $ | 2,716.8 | | | $ | 8,416.4 | | | $ | 7,445.9 | |
Transmission and Distribution Utilities | Transmission and Distribution Utilities | | 1,195.0 | | | 1,124.1 | | | 3,366.9 | | | 3,208.7 | | Transmission and Distribution Utilities | | 1,525.5 | | | 1,195.0 | | | 4,064.5 | | | 3,366.9 | |
Generation & Marketing | Generation & Marketing | | 617.4 | | | 464.8 | | | 1,641.6 | | | 1,223.4 | | Generation & Marketing | | 733.1 | | | 617.4 | | | 1,997.0 | | | 1,641.6 | |
Other Revenues | Other Revenues | | 93.8 | | | 77.4 | | | 276.2 | | | 220.4 | | Other Revenues | | 92.9 | | | 93.8 | | | 280.5 | | | 276.2 | |
TOTAL REVENUES | TOTAL REVENUES | | 4,623.0 | | | 4,066.4 | | | 12,730.6 | | | 11,307.9 | | TOTAL REVENUES | | 5,526.1 | | | 4,623.0 | | | 14,758.4 | | | 12,730.6 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 1,441.4 | | | 1,200.4 | | | 4,126.1 | | | 3,316.3 | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 2,111.9 | | | 1,441.4 | | | 5,177.0 | | | 4,126.1 | |
| Other Operation | Other Operation | | 735.3 | | | 702.9 | | | 1,894.6 | | | 1,871.0 | | Other Operation | | 797.0 | | | 735.3 | | | 2,079.0 | | | 1,894.6 | |
Maintenance | Maintenance | | 277.8 | | | 237.6 | | | 817.0 | | | 730.5 | | Maintenance | | 298.1 | | | 277.8 | | | 909.6 | | | 817.0 | |
| Loss on the Expected Sale of the Kentucky Operations | | Loss on the Expected Sale of the Kentucky Operations | | 194.5 | | | — | | | 263.3 | | | — | |
Asset Impairments and Other Related Charges | | Asset Impairments and Other Related Charges | | 24.9 | | | — | | | 24.9 | | | — | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | (37.0) | | | — | | | (37.0) | | | — | |
Gain on Sale of Mineral Rights | | Gain on Sale of Mineral Rights | | — | | | — | | | (116.3) | | | — | |
Depreciation and Amortization | Depreciation and Amortization | | 700.3 | | | 644.6 | | | 2,103.9 | | | 1,996.3 | | Depreciation and Amortization | | 821.8 | | | 700.3 | | | 2,416.8 | | | 2,103.9 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 360.8 | | | 337.7 | | | 1,061.4 | | | 976.3 | | Taxes Other Than Income Taxes | | 384.8 | | | 360.8 | | | 1,118.5 | | | 1,061.4 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 3,515.6 | | | 3,123.2 | | | 10,003.0 | | | 8,890.4 | | TOTAL EXPENSES | | 4,596.0 | | | 3,515.6 | | | 11,835.8 | | | 10,003.0 | |
| OPERATING INCOME | OPERATING INCOME | | 1,107.4 | | | 943.2 | | | 2,727.6 | | | 2,417.5 | | OPERATING INCOME | | 930.1 | | | 1,107.4 | | | 2,922.6 | | | 2,727.6 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
| Other Income (Expense) | Other Income (Expense) | | (20.6) | | | 5.5 | | | 34.2 | | | 15.4 | | Other Income (Expense) | | 4.8 | | | (20.6) | | | (5.6) | | | 34.2 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 37.0 | | | 45.2 | | | 103.9 | | | 111.7 | | Allowance for Equity Funds Used During Construction | | 35.6 | | | 37.0 | | | 95.2 | | | 103.9 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 29.6 | | | 29.7 | | | 88.9 | | | 89.2 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 47.2 | | | 29.6 | | | 141.5 | | | 88.9 | |
| Interest Expense | Interest Expense | | (303.7) | | | (291.3) | | | (895.5) | | | (877.4) | | Interest Expense | | (360.7) | | | (303.7) | | | (1,001.7) | | | (895.5) | |
| INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 849.7 | | | 732.3 | | | 2,059.1 | | | 1,756.4 | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS) | | INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS (LOSS) | | 657.0 | | | 849.7 | | | 2,152.0 | | | 2,059.1 | |
| Income Tax Expense (Benefit) | Income Tax Expense (Benefit) | | 69.8 | | | (1.2) | | | 185.5 | | | 57.9 | | Income Tax Expense (Benefit) | | (16.1) | | | 69.8 | | | 90.7 | | | 185.5 | |
Equity Earnings of Unconsolidated Subsidiaries | | 17.0 | | | 14.7 | | | 75.9 | | | 63.5 | | |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | | Equity Earnings (Loss) of Unconsolidated Subsidiaries | | 10.2 | | | 17.0 | | | (139.1) | | | 75.9 | |
| | NET INCOME | NET INCOME | | 796.9 | | | 748.2 | | | 1,949.5 | | | 1,762.0 | | NET INCOME | | 683.3 | | | 796.9 | | | 1,922.2 | | | 1,949.5 | |
| Net Income (Loss) Attributable to Noncontrolling Interests | Net Income (Loss) Attributable to Noncontrolling Interests | | 0.9 | | | (0.4) | | | 0.3 | | | (2.6) | | Net Income (Loss) Attributable to Noncontrolling Interests | | (0.4) | | | 0.9 | | | (0.7) | | | 0.3 | |
| EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 796.0 | | | $ | 748.6 | | | $ | 1,949.2 | | | $ | 1,764.6 | | EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 683.7 | | | $ | 796.0 | | | $ | 1,922.9 | | | $ | 1,949.2 | |
| WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 501,233,680 | | | 496,177,968 | | | 499,418,278 | | | 495,479,190 | | WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | 513,730,196 | | | 501,233,680 | | | 511,162,723 | | | 499,418,278 | |
| | TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.59 | | | $ | 1.51 | | | $ | 3.90 | | | $ | 3.56 | | TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.33 | | | $ | 1.59 | | | $ | 3.76 | | | $ | 3.90 | |
| WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 502,606,836 | | | 497,458,523 | | | 500,600,237 | | | 496,916,187 | | WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | 515,315,994 | | | 502,606,836 | | | 512,714,006 | | | 500,600,237 | |
| | TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.58 | | | $ | 1.50 | | | $ | 3.89 | | | $ | 3.55 | | TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.33 | | | $ | 1.58 | | | $ | 3.75 | | | $ | 3.89 | |
| | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 796.9 | | | $ | 748.2 | | | $ | 1,949.5 | | | $ | 1,762.0 | | Net Income | | $ | 683.3 | | | $ | 796.9 | | | $ | 1,922.2 | | | $ | 1,949.5 | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $47.8 and $10.5 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $97.3 and $4.7 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | 179.7 | | | 39.3 | | | 365.9 | | | 17.6 | | |
Cash Flow Hedges, Net of Tax of $(19.5) and $47.8 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $81.6 and $97.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $(19.5) and $47.8 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $81.6 and $97.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | (73.3) | | | 179.7 | | | 307.1 | | | 365.9 | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.5) and $(0.5) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(1.6) and $(1.4) for the Nine Months Ended September 30, 2021 and 2020, Respectively | | (2.0) | | | (1.8) | | | (6.1) | | | (5.3) | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.8) and $(0.5) for the Three Months Ended September 30, 2022 and 2021 and $(4.5) and $(1.6) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.8) and $(0.5) for the Three Months Ended September 30, 2022 and 2021 and $(4.5) and $(1.6) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | (3.2) | | | (2.0) | | | (17.0) | | | (6.1) | |
| | | | | | | | | | | | | | | | |
TOTAL OTHER COMPREHENSIVE INCOME | | 177.7 | | | 37.5 | | | 359.8 | | | 12.3 | | |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (76.5) | | | 177.7 | | | 290.1 | | | 359.8 | |
| TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | 974.6 | | | 785.7 | | | 2,309.3 | | | 1,774.3 | | TOTAL COMPREHENSIVE INCOME | | 606.8 | | | 974.6 | | | 2,212.3 | | | 2,309.3 | |
| Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests | Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests | | 0.9 | | | (0.4) | | | 0.3 | | | (2.6) | | Total Comprehensive Income (Loss) Attributable To Noncontrolling Interests | | (0.4) | | | 0.9 | | | (0.7) | | | 0.3 | |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 973.7 | | | $ | 786.1 | | | $ | 2,309.0 | | | $ | 1,776.9 | | TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 607.2 | | | $ | 973.7 | | | $ | 2,213.0 | | | $ | 2,309.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | AEP Common Shareholders | | | AEP Common Shareholders | |
| | Common Stock | | Accumulated Other Comprehensive Income (Loss) | | | 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 | | |
| Issuance of Common Stock | 0.4 | | | 2.2 | | | 23.3 | | | 25.5 | | |
Common Stock Dividends | | (349.1) | | (a) | | (2.0) | | | (351.1) | | |
Other Changes in Equity | | (104.0) | | (b) | | 0.3 | | | (103.7) | | |
| Net Income (Loss) | | 748.6 | | | (0.4) | | | 748.2 | | |
Other Comprehensive Income | | 37.5 | | | 37.5 | | |
TOTAL EQUITY – SEPTEMBER 30, 2020 | 516.6 | | | $ | 3,357.6 | | | $ | 6,522.3 | | | $ | 10,621.4 | | | $ | (135.4) | | | $ | 268.7 | | | $ | 20,634.6 | | |
| | | | | | | | | | | | | | | | Shares | | Amount | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | | Total |
TOTAL EQUITY – DECEMBER 31, 2020 | TOTAL EQUITY – DECEMBER 31, 2020 | 516.8 | | | $ | 3,359.3 | | | $ | 6,588.9 | | | $ | 10,687.8 | | | $ | (85.1) | | | $ | 223.6 | | | $ | 20,774.5 | | TOTAL EQUITY – DECEMBER 31, 2020 | 516.8 | | | $ | 3,359.3 | | | $ | 6,588.9 | | | $ | 10,687.8 | | | $ | 223.6 | | | $ | 20,774.5 | |
| Issuance of Common Stock | Issuance of Common Stock | 2.7 | | | 17.1 | | | 167.5 | | | 184.6 | | Issuance of Common Stock | 2.7 | | | 17.1 | | | 167.5 | | | | | 184.6 | |
Common Stock Dividends | Common Stock Dividends | | (369.5) | | (c) | | (2.5) | | | (372.0) | | Common Stock Dividends | | (369.5) | | (a) | | (2.5) | | | (372.0) | |
Other Changes in Equity | Other Changes in Equity | | (21.9) | | | (0.6) | | | 3.4 | | | (19.1) | | Other Changes in Equity | | (21.9) | | | (0.6) | | | 3.4 | | | (19.1) | |
| Acquisition of Dry Lake Solar Project | Acquisition of Dry Lake Solar Project | | 18.9 | | 18.9 | | Acquisition of Dry Lake Solar Project | | 18.9 | | | 18.9 | |
Net Income | Net Income | | 575.0 | | | 3.8 | | | 578.8 | | Net Income | | | | | | | 575.0 | | | 3.8 | | | 578.8 | |
Other Comprehensive Income | Other Comprehensive Income | | 54.3 | | | 54.3 | | Other Comprehensive Income | | | | | | | | | 54.3 | | | 54.3 | |
TOTAL EQUITY – MARCH 31, 2021 | TOTAL EQUITY – MARCH 31, 2021 | 519.5 | | | 3,376.4 | | | 6,734.5 | | | 10,892.7 | | | (30.8) | | | 247.2 | | | 21,220.0 | | 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 | Issuance of Common Stock | 0.9 | | | 6.3 | | | 66.0 | | | 72.3 | | Issuance of Common Stock | 0.9 | | | 6.3 | | | 66.0 | | | | | | | | | 72.3 | |
Common Stock Dividends | Common Stock Dividends | | (371.8) | | (c) | | (2.7) | | | (374.5) | | Common Stock Dividends | | | | | | | (371.8) | | (a) | | | (2.7) | | | (374.5) | |
Other Changes in Equity | Other Changes in Equity | | (0.2) | | | (0.4) | | | 11.1 | | | 10.5 | | Other Changes in Equity | | | | | (0.2) | | | (0.4) | | | | | 11.1 | | | 10.5 | |
| Net Income (Loss) | Net Income (Loss) | | 578.2 | | | (4.4) | | | 573.8 | | Net Income (Loss) | | | | | | | 578.2 | | | | | (4.4) | | | 573.8 | |
Other Comprehensive Income | Other Comprehensive Income | | 127.8 | | | 127.8 | | Other Comprehensive Income | | | | | | | | | 127.8 | | | | | 127.8 | |
TOTAL EQUITY – JUNE 30, 2021 | TOTAL EQUITY – JUNE 30, 2021 | 520.4 | | | 3,382.7 | | | 6,800.3 | | | 11,098.7 | | | 97.0 | | | 251.2 | | | 21,629.9 | | TOTAL EQUITY – JUNE 30, 2021 | 520.4 | | | 3,382.7 | | | 6,800.3 | | | 11,098.7 | | | 97.0 | | | 251.2 | | | 21,629.9 | |
| Issuance of Common Stock | Issuance of Common Stock | 3.4 | | | 21.8 | | | 269.3 | | | | | | | 291.1 | | Issuance of Common Stock | 3.4 | | | 21.8 | | | 269.3 | | | 291.1 | |
Common Stock Dividends | Common Stock Dividends | | | | | (371.7) | | (c) | | | (4.5) | | | (376.2) | | Common Stock Dividends | | (371.7) | | (a) | | (4.5) | | | (376.2) | |
Other Changes in Equity | Other Changes in Equity | | | | | 6.3 | | | | | 1.5 | | | 7.8 | | Other Changes in Equity | | 6.3 | | | 1.5 | | | 7.8 | |
Net Income | | Net Income | | 796.0 | | | 0.9 | | | 796.9 | |
Other Comprehensive Income | | Other Comprehensive Income | | 177.7 | | | 177.7 | |
TOTAL EQUITY – SEPTEMBER 30, 2021 | | TOTAL EQUITY – SEPTEMBER 30, 2021 | 523.8 | | | $ | 3,404.5 | | | $ | 7,075.9 | | | $ | 11,523.0 | | | $ | 274.7 | | | $ | 249.1 | | | $ | 22,527.2 | |
| TOTAL EQUITY – DECEMBER 31, 2021 | | TOTAL EQUITY – DECEMBER 31, 2021 | 524.4 | | | $ | 3,408.7 | | | $ | 7,172.6 | | | $ | 11,667.1 | | | $ | 184.8 | | | $ | 247.0 | | | $ | 22,680.2 | |
| Issuance of Common Stock | | Issuance of Common Stock | 0.4 | | | 2.4 | | | 807.1 | | | 809.5 | |
Common Stock Dividends | | Common Stock Dividends | | (395.2) | | (b) | | (3.6) | | | (398.8) | |
Other Changes in Equity | | Other Changes in Equity | | (15.2) | | | (1.5) | | | (16.7) | |
| Net Income | Net Income | | | | | | | 796.0 | | | | | 0.9 | | | 796.9 | | Net Income | | 714.7 | | | 3.4 | | | 718.1 | |
Other Comprehensive Income | Other Comprehensive Income | | | | | | | | | 177.7 | | | | | 177.7 | | Other Comprehensive Income | | 245.8 | | | 245.8 | |
TOTAL EQUITY – SEPTEMBER 30, 2021 | 523.8 | | | $ | 3,404.5 | | | $ | 7,075.9 | | | $ | 11,523.0 | | | $ | 274.7 | | | $ | 249.1 | | | $ | 22,527.2 | | |
TOTAL EQUITY – MARCH 31, 2022 | | TOTAL EQUITY – MARCH 31, 2022 | 524.8 | | | 3,411.1 | | | 7,964.5 | | | 11,985.1 | | | 430.6 | | | 246.8 | | | 24,038.1 | |
| Issuance of Common Stock | | Issuance of Common Stock | 0.1 | | | 0.9 | | | 2.3 | | | 3.2 | |
Common Stock Dividends | | Common Stock Dividends | | (402.6) | | (b) | | (2.1) | | | (404.7) | |
Other Changes in Equity | | Other Changes in Equity | | 17.2 | | | 1.6 | | | 18.8 | |
| Net Income (Loss) | | Net Income (Loss) | | 524.5 | | | (3.7) | | | 520.8 | |
Other Comprehensive Income | | Other Comprehensive Income | | 120.8 | | | 120.8 | |
TOTAL EQUITY – JUNE 30, 2022 | | TOTAL EQUITY – JUNE 30, 2022 | 524.9 | | | 3,412.0 | | | 7,984.0 | | | 12,108.6 | | | 551.4 | | | 241.0 | | | 24,297.0 | |
| Issuance of Common Stock | | Issuance of Common Stock | 0.1 | | | 0.5 | | | 14.0 | | | | | | | 14.5 | |
Common Stock Dividends | | Common Stock Dividends | | | | | (402.5) | | (b) | | | (6.5) | | | (409.0) | |
Other Changes in Equity | | Other Changes in Equity | | | | | 3.0 | | | | | 3.0 | |
Net Income (Loss) | | Net Income (Loss) | | | | | | | 683.7 | | | | | (0.4) | | | 683.3 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | | | | | | | | (76.5) | | | | | (76.5) | |
TOTAL EQUITY – SEPTEMBER 30, 2022 | | TOTAL EQUITY – SEPTEMBER 30, 2022 | 525.0 | | | $ | 3,412.5 | | | $ | 8,001.0 | | | $ | 12,389.8 | | | $ | 474.9 | | | $ | 234.1 | | | $ | 24,512.3 | |
(a) Cash dividends declared per AEP common share were $0.70.$0.74.
(b) Includes $(121) million related to a forward equity purchase contract associated with the issuance of Equity Units.
(c) Cash dividends declared per AEP common share were $0.74.$0.78.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138144. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 1,372.7 | | | $ | 392.7 | | Cash and Cash Equivalents | | $ | 522.2 | | | $ | 403.4 | |
Restricted Cash (September 30, 2021 and December 31, 2020 Amounts Include $54 and $45.6, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding) | | 54.0 | | | 45.6 | | |
Other Temporary Investments (September 30, 2021 and December 31, 2020 Amounts Include $211.5 and $194.6, Respectively, Related to EIS and Transource Energy) | | 218.4 | | | 200.8 | | |
Restricted Cash (September 30, 2022 and December 31, 2021 Amounts Include $55.1 and $48, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding) | | Restricted Cash (September 30, 2022 and December 31, 2021 Amounts Include $55.1 and $48, Respectively, Related to Transition Funding, Restoration Funding and Appalachian Consumer Rate Relief Funding) | | 55.1 | | | 48.0 | |
Other Temporary Investments (September 30, 2022 and December 31, 2021 Amounts Include $188.4 and $214.8, Respectively, Related to EIS and Transource Energy) | | Other Temporary Investments (September 30, 2022 and December 31, 2021 Amounts Include $188.4 and $214.8, Respectively, Related to EIS and Transource Energy) | | 202.2 | | | 220.4 | |
Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 701.2 | | | 613.6 | | Customers | | 885.6 | | | 720.9 | |
Accrued Unbilled Revenues | Accrued Unbilled Revenues | | 279.3 | | | 248.7 | | Accrued Unbilled Revenues | | 272.2 | | | 204.4 | |
Pledged Accounts Receivable – AEP Credit | Pledged Accounts Receivable – AEP Credit | | 1,071.1 | | | 1,018.4 | | Pledged Accounts Receivable – AEP Credit | | 1,211.9 | | | 1,038.0 | |
Miscellaneous | Miscellaneous | | 50.5 | | | 33.1 | | Miscellaneous | | 84.8 | | | 33.9 | |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | | (51.7) | | | (71.1) | | Allowance for Uncollectible Accounts | | (53.2) | | | (55.6) | |
Total Accounts Receivable | Total Accounts Receivable | | 2,050.4 | | | 1,842.7 | | Total Accounts Receivable | | 2,401.3 | | | 1,941.6 | |
Fuel | Fuel | | 290.1 | | | 629.4 | | Fuel | | 332.1 | | | 307.9 | |
Materials and Supplies | Materials and Supplies | | 688.4 | | | 680.6 | | Materials and Supplies | | 801.9 | | | 681.3 | |
Risk Management Assets | Risk Management Assets | | 369.2 | | | 94.7 | | Risk Management Assets | | 570.2 | | | 194.4 | |
Accrued Tax Benefits | Accrued Tax Benefits | | 226.6 | | | 185.3 | | Accrued Tax Benefits | | 150.8 | | | 121.5 | |
Regulatory Asset for Under-Recovered Fuel Costs | Regulatory Asset for Under-Recovered Fuel Costs | | 307.0 | | | 90.7 | | Regulatory Asset for Under-Recovered Fuel Costs | | 1,137.1 | | | 647.8 | |
Margin Deposits | | 73.2 | | | 62.0 | | |
| Assets Held for Sale | | Assets Held for Sale | | 2,830.6 | | | 2,919.7 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 135.1 | | | 127.0 | | Prepayments and Other Current Assets | | 316.5 | | | 323.2 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 5,785.1 | | | 4,351.5 | | TOTAL CURRENT ASSETS | | 9,320.0 | | | 7,809.2 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Generation | Generation | | 24,135.9 | | | 23,133.9 | | Generation | | 24,590.7 | | | 23,088.1 | |
Transmission | Transmission | | 29,555.1 | | | 27,886.7 | | Transmission | | 31,271.5 | | | 29,911.1 | |
Distribution | Distribution | | 25,057.7 | | | 23,972.1 | | Distribution | | 25,566.1 | | | 24,440.0 | |
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 5,668.5 | | | 5,294.6 | | Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 6,080.8 | | | 5,682.9 | |
Construction Work in Progress | Construction Work in Progress | | 4,151.0 | | | 4,025.7 | | Construction Work in Progress | | 4,596.0 | | | 3,684.3 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 88,568.2 | | | 84,313.0 | | Total Property, Plant and Equipment | | 92,105.1 | | | 86,806.4 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 21,877.0 | | | 20,411.4 | | Accumulated Depreciation and Amortization | | 22,292.0 | | | 20,805.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 66,691.2 | | | 63,901.6 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 69,813.1 | | | 66,001.3 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 5,031.5 | | | 3,527.0 | | Regulatory Assets | | 3,877.5 | | | 4,142.3 | |
Securitized Assets | Securitized Assets | | 580.4 | | | 657.0 | | Securitized Assets | | 474.3 | | | 552.8 | |
Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | 3,609.8 | | | 3,306.7 | | Spent Nuclear Fuel and Decommissioning Trusts | | 3,130.5 | | | 3,867.0 | |
Goodwill | Goodwill | | 52.5 | | | 52.5 | | Goodwill | | 52.5 | | | 52.5 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 278.3 | | | 242.2 | | Long-term Risk Management Assets | | 265.8 | | | 267.0 | |
Operating Lease Assets | Operating Lease Assets | | 779.8 | | | 866.4 | | Operating Lease Assets | | 620.0 | | | 578.3 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 3,528.5 | | | 3,852.3 | | Deferred Charges and Other Noncurrent Assets | | 3,695.7 | | | 4,398.3 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 13,860.8 | | | 12,504.1 | | TOTAL OTHER NONCURRENT ASSETS | | 12,116.3 | | | 13,858.2 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 86,337.1 | | | $ | 80,757.2 | | TOTAL ASSETS | | $ | 91,249.4 | | | $ | 87,668.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20212022 and December 31, 20202021
(in millions, except per-share and share amounts)
(Unaudited)
| | | | | | | | September 30, | | December 31, | | | | | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Accounts Payable | Accounts Payable | | | $ | 1,597.1 | | | $ | 1,709.7 | | Accounts Payable | | | $ | 2,240.2 | | | $ | 2,054.6 | |
Short-term Debt: | Short-term Debt: | | | | | Short-term Debt: | | | | |
Securitized Debt for Receivables – AEP Credit | Securitized Debt for Receivables – AEP Credit | | 750.0 | | | 592.0 | | Securitized Debt for Receivables – AEP Credit | | 750.0 | | | 750.0 | |
Other Short-term Debt | Other Short-term Debt | | 1,754.0 | | | 1,887.3 | | Other Short-term Debt | | 1,952.3 | | | 1,864.0 | |
Total Short-term Debt | Total Short-term Debt | | 2,504.0 | | | 2,479.3 | | Total Short-term Debt | | 2,702.3 | | | 2,614.0 | |
Long-term Debt Due Within One Year (September 30, 2021 and December 31, 2020 Amounts Include $203.2 and $198.3, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | 2,521.8 | | | 2,086.1 | | |
Long-term Debt Due Within One Year (September 30, 2022 and December 31, 2021 Amounts Include $196.4 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | Long-term Debt Due Within One Year (September 30, 2022 and December 31, 2021 Amounts Include $196.4 and $190.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | 1,403.5 | | | 2,153.8 | |
Risk Management Liabilities | Risk Management Liabilities | | 106.5 | | | 78.8 | | Risk Management Liabilities | | 187.3 | | | 75.4 | |
Customer Deposits | Customer Deposits | | 400.2 | | | 335.6 | | Customer Deposits | | 375.5 | | | 321.6 | |
Accrued Taxes | Accrued Taxes | | 1,046.6 | | | 1,476.4 | | Accrued Taxes | | 1,116.9 | | | 1,586.4 | |
Accrued Interest | Accrued Interest | | 349.7 | | | 267.6 | | Accrued Interest | | 375.4 | | | 273.2 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 241.8 | | | 241.3 | | Obligations Under Operating Leases | | 91.7 | | | 97.6 | |
Regulatory Liability for Over-Recovered Fuel Costs | | 3.5 | | | 52.6 | | |
| Liabilities Held for Sale | | Liabilities Held for Sale | | 1,992.0 | | | 1,880.9 | |
Other Current Liabilities | Other Current Liabilities | | 1,182.8 | | | 1,199.3 | | Other Current Liabilities | | 1,351.6 | | | 1,369.2 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 9,954.0 | | | 9,926.7 | | TOTAL CURRENT LIABILITIES | | 11,836.4 | | | 12,426.7 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt (September 30, 2021 and December 31, 2020 Amounts Include $887 and $950.1, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | | 32,056.5 | | | 28,986.4 | | |
Long-term Debt (September 30, 2022 and December 31, 2021 Amounts Include $764 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | Long-term Debt (September 30, 2022 and December 31, 2021 Amounts Include $764 and $840.5, Respectively, Related to Sabine, DCC Fuel, Transition Funding, Restoration Funding, Appalachian Consumer Rate Relief Funding and Transource Energy) | | | 33,646.6 | | | 31,300.7 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 199.6 | | | 232.8 | | Long-term Risk Management Liabilities | | 388.2 | | | 230.3 | |
Deferred Income Taxes | Deferred Income Taxes | | 8,644.8 | | | 8,240.9 | | Deferred Income Taxes | | 8,544.8 | | | 8,202.5 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 8,687.8 | | | 8,378.7 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 7,934.1 | | | 8,686.3 | |
Asset Retirement Obligations | Asset Retirement Obligations | | 2,612.0 | | | 2,469.2 | | Asset Retirement Obligations | | 2,855.1 | | | 2,676.2 | |
Employee Benefits and Pension Obligations | Employee Benefits and Pension Obligations | | 322.2 | | | 336.4 | | Employee Benefits and Pension Obligations | | 279.9 | | | 328.4 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 586.8 | | | 638.4 | | Obligations Under Operating Leases | | 540.0 | | | 492.8 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 672.9 | | | 728.0 | | Deferred Credits and Other Noncurrent Liabilities | | 638.7 | | | 601.3 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 53,782.6 | | | 50,010.8 | | TOTAL NONCURRENT LIABILITIES | | 54,827.4 | | | 52,518.5 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 63,736.6 | | | 59,937.5 | | TOTAL LIABILITIES | | 66,663.8 | | | 64,945.2 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| MEZZANINE EQUITY | MEZZANINE EQUITY | | MEZZANINE EQUITY | |
| Contingently Redeemable Performance Share Awards | Contingently Redeemable Performance Share Awards | | | 73.3 | | | 45.2 | | Contingently Redeemable Performance Share Awards | | | 73.3 | | | 43.3 | |
TOTAL MEZZANINE EQUITY | TOTAL MEZZANINE EQUITY | | 73.3 | | | 45.2 | | TOTAL MEZZANINE EQUITY | | 73.3 | | | 43.3 | |
| EQUITY | EQUITY | | | | | EQUITY | | | | |
Common Stock – Par Value – $6.50 Per Share: | Common Stock – Par Value – $6.50 Per Share: | | | | | | Common Stock – Par Value – $6.50 Per Share: | | | | | |
| | 2021 | | 2020 | | | | | | 2022 | | 2021 | | | | |
Shares Authorized | Shares Authorized | | 600,000,000 | | 600,000,000 | | | | | Shares Authorized | | 600,000,000 | | 600,000,000 | | | | |
Shares Issued | Shares Issued | | 523,773,631 | | 516,808,354 | | | | | Shares Issued | | 525,005,433 | | 524,416,175 | | | | |
(20,204,160 Shares were Held in Treasury as of September 30, 2021 and December 31, 2020, Respectively) | | 3,404.5 | | | 3,359.3 | | |
(11,233,240 Shares and 20,204,160 Shares were Held in Treasury as of September 30, 2022 and December 31, 2021, Respectively) | | (11,233,240 Shares and 20,204,160 Shares were Held in Treasury as of September 30, 2022 and December 31, 2021, Respectively) | | 3,412.5 | | | 3,408.7 | |
Paid-in Capital | Paid-in Capital | | 7,075.9 | | | 6,588.9 | | Paid-in Capital | | 8,001.0 | | | 7,172.6 | |
Retained Earnings | Retained Earnings | | 11,523.0 | | | 10,687.8 | | Retained Earnings | | 12,389.8 | | | 11,667.1 | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | 274.7 | | | (85.1) | | Accumulated Other Comprehensive Income (Loss) | | 474.9 | | | 184.8 | |
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | 22,278.1 | | | 20,550.9 | | TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | 24,278.2 | | | 22,433.2 | |
| Noncontrolling Interests | Noncontrolling Interests | | 249.1 | | | 223.6 | | Noncontrolling Interests | | 234.1 | | | 247.0 | |
| TOTAL EQUITY | TOTAL EQUITY | | 22,527.2 | | | 20,774.5 | | TOTAL EQUITY | | 24,512.3 | | | 22,680.2 | |
| TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | $ | 86,337.1 | | | $ | 80,757.2 | | TOTAL LIABILITIES, MEZZANINE EQUITY AND TOTAL EQUITY | | $ | 91,249.4 | | | $ | 87,668.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited) | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2021 | | 2020 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 1,949.5 | | | $ | 1,762.0 | |
| | | | |
| | | | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 2,103.9 | | | 1,996.3 | |
Rockport Rent, Unit 2 Operating Lease Amortization | | 100.8 | | | 102.4 | |
Deferred Income Taxes | | 191.1 | | | 142.5 | |
| | | | |
| | | | |
Allowance for Equity Funds Used During Construction | | (103.9) | | | (111.7) | |
Mark-to-Market of Risk Management Contracts | | 101.0 | | | 46.4 | |
Amortization of Nuclear Fuel | | 61.9 | | | 67.2 | |
Pension Contributions to Qualified Plan Trust | | — | | | (110.3) | |
Property Taxes | | 415.1 | | | 396.9 | |
Deferred Fuel Over/Under-Recovery, Net | | (1,356.8) | | | 27.4 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Change in Other Noncurrent Assets | | (270.7) | | | (322.0) | |
Change in Other Noncurrent Liabilities | | 162.7 | | | (25.1) | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (199.2) | | | (138.9) | |
Fuel, Materials and Supplies | | 347.4 | | | (97.4) | |
Accounts Payable | | 107.6 | | | 21.9 | |
Accrued Taxes, Net | | (471.1) | | | (502.9) | |
Rockport Plant, Unit 2 Operating Lease Payments | | (73.9) | | | (73.9) | |
Other Current Assets | | (33.3) | | | 26.0 | |
Other Current Liabilities | | (59.1) | | | (284.6) | |
Net Cash Flows from Operating Activities | | 2,973.0 | | | 2,922.2 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (4,087.0) | | | (4,690.4) | |
| | | | |
Purchases of Investment Securities | | (1,612.3) | | | (1,329.5) | |
Sales of Investment Securities | | 1,571.7 | | | 1,293.0 | |
Acquisitions of Nuclear Fuel | | (63.2) | | | (68.4) | |
Acquisition of the Dry Lake Solar Project | | (114.4) | | | — | |
| | | | |
| | | | |
Acquisition of the North Central Wind Energy Facilities | | (652.8) | | | — | |
Other Investing Activities | | 51.8 | | | 88.0 | |
Net Cash Flows Used for Investing Activities | | (4,906.2) | | | (4,707.3) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Common Stock | | 548.0 | | | 136.5 | |
Issuance of Long-term Debt | | 5,062.3 | | | 3,985.8 | |
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 | | (632.5) | | | (1,445.8) | |
Retirement of Long-term Debt | | (1,549.8) | | | (700.5) | |
| | | | |
Redemption of Short-term Debt with Original Maturities Greater than 90 Days | | (521.3) | | | (300.0) | |
Principal Payments for Finance Lease Obligations | | (45.3) | | | (46.3) | |
Dividends Paid on Common Stock | | (1,122.7) | | | (1,055.7) | |
Redemption of Noncontrolling Interest in Trent and Desert Sky Windfarms | | — | | | (56.5) | |
Other Financing Activities | | 4.4 | | | (5.7) | |
Net Cash Flows from Financing Activities | | 2,921.6 | | | 1,816.3 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Net Increase in Cash and Cash Equivalents | | 988.4 | | | 31.2 | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 438.3 | | | 432.6 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 1,426.7 | | | $ | 463.8 | |
| | | | |
SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 775.2 | | | $ | 690.5 | |
Net Cash Paid (Received) for Income Taxes | | 9.3 | | | (23.9) | |
Noncash Acquisitions Under Finance Leases | | 23.0 | | | 33.0 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 764.1 | | | 830.1 | |
Construction Expenditures Included in Noncurrent Liabilities as of September 30, | | — | | | 8.3 | |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 0.3 | | | 1.0 | |
| | | | |
Noncash Contribution of Assets to Cedar Creek Project | | (9.3) | | | — | |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | | 0.6 | | | 2.4 | |
Noncontrolling Interest Assumed - Dry Lake Solar Project | | 35.0 | | | — | |
| | | | |
Forward Equity Purchase Contract Included in Current and Noncurrent Liabilities as of September 30, | | — | | | 120.6 | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. |
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2022 | | 2021 |
OPERATING ACTIVITIES | | | | |
Net Income | | $ | 1,922.2 | | | $ | 1,949.5 | |
| | | | |
| | | | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | | 2,416.8 | | | 2,103.9 | |
| | | | |
Deferred Income Taxes | | 16.6 | | | 191.1 | |
Loss on the Expected Sale of the Kentucky Operations | | 263.3 | | | — | |
Asset Impairments and Other Related Charges | | 24.9 | | | — | |
Impairment of Equity Method Investment | | 188.0 | | | — | |
Allowance for Equity Funds Used During Construction | | (95.2) | | | (103.9) | |
Mark-to-Market of Risk Management Contracts | | 162.3 | | | 101.0 | |
| | | | |
| | | | |
Property Taxes | | 459.9 | | | 415.1 | |
Deferred Fuel Over/Under-Recovery, Net | | (148.7) | | | (1,356.8) | |
Gain on Sale of Mineral Rights | | (116.3) | | | — | |
| | | | |
| | | | |
| | | | |
| | | | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | (37.0) | | | — | |
Change in Other Noncurrent Assets | | (6.0) | | | (108.0) | |
Change in Other Noncurrent Liabilities | | 324.0 | | | 162.7 | |
Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | | (495.7) | | | (199.2) | |
Fuel, Materials and Supplies | | (134.6) | | | 347.4 | |
Accounts Payable | | 369.4 | | | 107.6 | |
Accrued Taxes, Net | | (512.8) | | | (471.1) | |
| | | | |
Other Current Assets | | 41.2 | | | (33.3) | |
Other Current Liabilities | | 90.9 | | | (133.0) | |
Net Cash Flows from Operating Activities | | 4,733.2 | | | 2,973.0 | |
| | | | |
INVESTING ACTIVITIES | | | | |
Construction Expenditures | | (4,748.5) | | | (4,087.0) | |
| | | | |
Purchases of Investment Securities | | (1,868.2) | | | (1,612.3) | |
Sales of Investment Securities | | 1,833.4 | | | 1,571.7 | |
Acquisitions of Nuclear Fuel | | (91.9) | | | (63.2) | |
Acquisition of the Dry Lake Solar Project | | — | | | (114.4) | |
Acquisition of the North Central Wind Energy Facilities | | (1,207.3) | | | (652.8) | |
Proceeds from Sales of Assets | | 215.7 | | | 17.4 | |
Other Investing Activities | | 44.3 | | | 34.4 | |
Net Cash Flows Used for Investing Activities | | (5,822.5) | | | (4,906.2) | |
| | | | |
FINANCING ACTIVITIES | | | | |
Issuance of Common Stock | | 827.2 | | | 548.0 | |
Issuance of Long-term Debt | | 3,428.4 | | | 5,062.3 | |
Issuance of Short-term Debt with Original Maturities greater than 90 Days | | 271.0 | | | 1,178.5 | |
Change in Short-term Debt with Original Maturities less than 90 Days, Net | | 803.4 | | | (632.5) | |
Retirement of Long-term Debt | | (1,679.1) | | | (1,549.8) | |
| | | | |
Redemption of Short-term Debt with Original Maturities Greater than 90 Days | | (986.1) | | | (521.3) | |
Principal Payments for Finance Lease Obligations | | (120.3) | | | (45.3) | |
Dividends Paid on Common Stock | | (1,212.5) | | | (1,122.7) | |
| | | | |
Other Financing Activities | | (116.8) | | | 4.4 | |
Net Cash Flows from Financing Activities | | 1,215.2 | | | 2,921.6 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Net Increase in Cash and Cash Equivalents | | 125.9 | | | 988.4 | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 451.4 | | | 438.3 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 577.3 | | | $ | 1,426.7 | |
|
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC.
AND SUBSIDIARIES
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | Retail: | | | | |
Residential | Residential | 3,997 | | | 4,112 | | | 9,821 | | | 9,736 | | Residential | 4,079 | | | 3,997 | | | 10,453 | | | 9,821 | |
Commercial | Commercial | 3,014 | | | 2,941 | | | 7,907 | | | 7,700 | | Commercial | 3,243 | | | 3,014 | | | 8,482 | | | 7,907 | |
Industrial | Industrial | 2,414 | | | 2,037 | | | 6,898 | | | 6,618 | | Industrial | 2,993 | | | 2,414 | | | 8,443 | | | 6,898 | |
Miscellaneous | Miscellaneous | 182 | | | 184 | | | 478 | | | 486 | | Miscellaneous | 185 | | | 182 | | | 499 | | | 478 | |
Total Retail | Total Retail | 9,607 | | | 9,274 | | | 25,104 | | | 24,540 | | Total Retail | 10,500 | | | 9,607 | | | 27,877 | | | 25,104 | |
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | — | | | 1 | | | 319 | | | 98 | | Actual – Heating (a) | — | | | — | | | 278 | | | 319 | |
Normal – Heating (b) | Normal – Heating (b) | — | | | — | | | 188 | | | 188 | | Normal – Heating (b) | — | | | — | | | 193 | | | 188 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 1,308 | | | 1,357 | | | 2,278 | | | 2,524 | | Actual – Cooling (c) | 1,478 | | | 1,308 | | | 2,701 | | | 2,278 | |
Normal – Cooling (b) | Normal – Cooling (b) | 1,379 | | | 1,378 | | | 2,436 | | | 2,436 | | Normal – Cooling (b) | 1,382 | | | 1,379 | | | 2,433 | | | 2,436 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
AEP Texas Inc. and Subsidiaries |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
|
Third Quarter of 20202021 | | $ | 82.699.5 | |
| | |
Changes in Gross Margin:Revenues: | | |
Retail MarginsRevenues | | 29.844.0 | |
Margins from Off-system Sales | | (30.1) | |
Transmission Revenues | | 29.79.3 | |
Other Revenues | | (18.4)23.0 | |
Total Change in Gross MarginRevenues | | 11.076.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (2.6)(29.2) | |
Depreciation and Amortization | | 20.1 (30.1) | |
Taxes Other Than Income Taxes | | (2.9)(3.9) | |
| | |
Interest Income | | (0.3)1.1 | |
| | |
Allowance for Equity Funds Used During Construction | | 4.8 (4.0) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 1.4 | |
Interest Expense | | 0.3 (11.2) | |
Total Change in Expenses and Other | | 19.4 (75.9) | |
| | |
Income Tax Expense | | (13.5)(6.3) | |
| | |
Third Quarter of 20212022 | | $ | 99.593.6 | |
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 MarginsRevenues increased $30$44 million primarily due to the following:
•A $22$21 million increase due to prior year refunds of Excess ADIT and excess federal income taxes collected as a result of Tax Reform. This increase was partially offset in Income Tax Expense below.interim rate increases driven by increased transmission investment.
•A $13$10 million increase fromdue to interim rate increases driven by increased distribution investment.
•A $3$7 million increase in weather-related usage primarily due to a 13% increase in cooling degree days.
•A $6 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•Transmission Revenues increased $9 million primarily due to the following:
•An $11 million increase due to interim rate increases driven by increased transmission investment.
These increases wereThis increase was partially offset by:
•A $9$2 million decrease in weather-normalized margins primarily in the industrial class.
•A $3 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days.
•Margins from Off-system Sales decreased $30 million primarily dueprior year refunds to customers associated with the retirement of the Oklaunion Power Station in September 2020.most recent base rate case. This decrease was partially offset in Depreciation and Amortization expensesOther Revenues below.
•TransmissionOther Revenues increased $30$23 million primarily due to the following:
•A $20$19 million increase fromprimarily due to securitization revenues due to AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset below in Depreciation and Amortization expenses and Interest Expense.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $29 million primarily due to the following:
•A $21 million increase in ERCOT transmission expenses. This increase was partially offset in Retail Revenues and Transmission Revenues above.
•A $6 million increase in distribution-related expenses.
•Depreciation and Amortization expenses increased $30 million primarily due to the following:
•A $19 million increase in securitization amortizations primarily due to prior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020 and final refunds that were completed in 2021. This increase was offset above in Other Revenues above.
•A $6 million increase due to a higher depreciable base of transmission and distribution assets.
•A $4 million increase in recoverable advanced metering system depreciable expenses.
•Taxes Other Than Income Taxes increased $4 million primarily due to property taxes as a result of increased distribution and transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4 million due to a prior year rate adjustment.
•Interest Expense increased $11 million primarily due to higher long-term debt balances and higher interest rates.
•Income Tax Expense increased $6 million primarily due to a decrease in amortization of Excess ADIT.The decrease in amortization of Excess ADIT was offset in Retail Revenues above.
Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021
| | | | | | | | |
AEP Texas Inc. and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 2021 to Nine Months Ended September 30, 2022 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 2021 | | $ | 225.4 | |
| | |
Changes in Revenues: | | |
Retail Revenues | | 151.2 | |
| | |
Transmission Revenues | | 53.2 | |
Other Revenues | | 4.7 | |
Total Change in Revenues | | 209.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (74.8) | |
Depreciation and Amortization | | (55.6) | |
Taxes Other Than Income Taxes | | (8.4) | |
| | |
Interest Income | | 2.1 | |
| | |
Allowance for Equity Funds Used During Construction | | (3.5) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 4.2 | |
Interest Expense | | (20.7) | |
Total Change in Expenses and Other | | (156.7) | |
| | |
Income Tax Expense | | (24.6) | |
| | |
Nine Months Ended September 30, 2022 | | $ | 253.2 | |
The major components of the increase in revenues were as follows:
•Retail Revenues increased $151 million primarily due to the following:
•A $41 million increase due to interim rate increases driven by increased transmission investment.
•An $8A $31 million increase due to prior year refunds of Excess ADIT to customers. This increase was offset in Income Tax Expense below.
•A $29 million increase due to interim rate increases driven by increased distribution investment.
•A $20 million increase in revenue from rate riders. This increase was partially offset in other expense items below.
•A $16 million increase in weather-normalized revenues in all retail classes.
•A $15 million increase in weather-related usage primarily due to a 19% increase in cooling degree days partially offset by a 13% decrease in heating degree days.
•Transmission Revenues increased $53 million primarily due to the following:
•A $46 million increase due to interim rate increases driven by increased transmission investment.
•A $7 million increase due to prior year refunds to customers associated with the most recent base rate case. This increase was offset in Other Revenues below.
•Other Revenues decreased $18increased $5 million primarily due to the following:to:
•A $10$20 million decrease inincrease primarily due to securitization revenues primarily due todriven by the AEP Texas Central Transition Funding II LLC bonds that matured in July 2020.2020 and final refunds that were completed in 2021. This decreaseincrease was offset below in Depreciation and Amortization expenses and in Interest Expense.
•An $8A $2 million increase in pole attachment revenues.
These increases were partially offset by:
•A $12 million decrease due to prior year refunds to customers associated with the most recent base rate case. This decrease was partially offset in Retail MarginsRevenues and Transmission Revenues above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $3 million primarily due to the following:
•A $5 million increase in transmission expenses. This increase was partially offset in Gross Margin above.
•A $2 million increase in distribution-related expenses.
These increases were partially offset by:
•A $5 million decrease due to the prior year write-off of land associated with the Oklaunion Power Station.
•Depreciation and Amortization expenses decreased $20 million primarily due to the following:
•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.
•A $9 million decrease in securitization amortizations 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 $7 million increase in depreciation expense due to an increase in the depreciable base of transmission
and distribution assets.
•Allowance for Equity Funds Used During Construction increased $5 million due to a current year adjustment to rates.
•Income Tax Expense increased $14 million primarily due to an increase in pretax book income, a decrease in amortization of Excess ADIT and the recognition of a favorable discrete adjustment in the prior year. The decrease in amortization of Excess ADIT was partially offset above in Gross Margin.
energy efficiency revenues.
Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020
| | | | | | | | |
AEP Texas Inc. and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 2020 to Nine Months Ended September 30, 2021 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 2020 | | $ | 197.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 54.2 | |
Margins from Off-system Sales | | (73.2) | |
Transmission Revenues | | 74.5 | |
Other Revenues | | (103.7) | |
Total Change in Gross Margin | | (48.2) | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (18.1) | |
Depreciation and Amortization | | 148.7 | |
Taxes Other Than Income Taxes | | (10.7) | |
| | |
Interest Income | | (0.6) | |
| | |
Allowance for Equity Funds Used During Construction | | 2.3 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1) | |
Interest Expense | | (3.3) | |
Total Change in Expenses and Other | | 118.2 | |
| | |
Income Tax Expense | | (41.7) | |
| | |
Nine Months Ended September 30, 2021 | | $ | 225.4 | |
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 Margins increased $54 million primarily due to the following:
•A $34 million increase from interim rate increases driven by increased distribution investment.
•An $18 million increase from interim rate increases driven by increased transmission investment.
•A $10 million increase in weather-related usage primarily due to a 226% increase in heating degree days partially offset by a 10% decrease in cooling degree days.
These increases were partially offset by:
•An $8 million decrease in weather-normalized margins primarily in the industrial class.
•Margins from Off-system Sales decreased $73 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 $75 million primarily due to the following:
•A $59 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.
•Other Revenues decreased $104 million primarily due to securitization revenues driven by 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.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $18$75 million primarily due to the following:
•A $17$46 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.
•An $8 million increase inERCOT transmission expenses. This increase was partially offset in Gross MarginRetail Revenues and Transmission Revenues above.
These increases were partially offset by:•A $13 million increase in distribution-related expenses.
•A $10 million increase in employee-related expenses.
•A $5 million decrease due to the prior year write-off of land associated with the Oklaunion Power Station.increase in vegetation management expenses.
•Depreciation and Amortization expenses decreased $149increased $56 million primarily due to the following:
•A $102$24 million decreaseincrease due to a higher depreciable base and amortizations of transmission and distribution assets.
•A $19 million increase in securitization amortizations primarily relateddue to theprior year AEP Texas Central Transition Funding II LLC bonds that matured in July 2020. 2020 and final refunds that were completed in 2021. This decreaseincrease was offset above in Other Revenues above.Revenue.
•A $48An $11 million decreaseincrease 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 Maintenancerecoverable advanced metering system depreciable expenses.
•Taxes Other Than Income Taxes increased $11$8 million primarily due to property taxes as a result of increased distribution and transmission investment.
•Allowance for Equity Funds Used During Construction decreased $4 milliondue to a prior year rate adjustment.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $4 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $3$21 million primarily due to higher long-term debt balances.balances and higher interest rates.
•Income Tax Expense increased $42$25 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT and an increase in pretax book income.ADIT. The decrease in amortization of Excess ADIT was partially offset above in Gross Margin.Retail Revenues above.
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electric Transmission and Distribution | Electric Transmission and Distribution | | $ | 430.8 | | | $ | 390.1 | | | $ | 1,189.1 | | | $ | 1,165.2 | | Electric Transmission and Distribution | | $ | 507.7 | | | $ | 430.8 | | | $ | 1,399.3 | | | $ | 1,189.1 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 0.9 | | | 41.4 | | | 2.9 | | | 89.4 | | Sales to AEP Affiliates | | 0.9 | | | 0.9 | | | 2.6 | | | 2.9 | |
Other Revenues | Other Revenues | | 0.9 | | | 0.5 | | | 3.3 | | | 2.5 | | Other Revenues | | 0.3 | | | 0.9 | | | 2.5 | | | 3.3 | |
TOTAL REVENUES | TOTAL REVENUES | | 432.6 | | | 432.0 | | | 1,195.3 | | | 1,257.1 | | TOTAL REVENUES | | 508.9 | | | 432.6 | | | 1,404.4 | | | 1,195.3 | |
| | | | | | | | | | | | | | | | | | |
EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | — | | | 10.4 | | | — | | | 13.6 | | |
| Other Operation | Other Operation | | 135.3 | | | 134.3 | | | 367.1 | | | 344.7 | | Other Operation | | 163.8 | | | 135.3 | | | 431.6 | | | 367.1 | |
Maintenance | Maintenance | | 22.0 | | | 20.4 | | | 59.8 | | | 64.1 | | Maintenance | | 22.7 | | | 22.0 | | | 70.1 | | | 59.8 | |
Depreciation and Amortization | Depreciation and Amortization | | 87.6 | | | 107.7 | | | 287.1 | | | 435.8 | | Depreciation and Amortization | | 117.7 | | | 87.6 | | | 342.7 | | | 287.1 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 41.6 | | | 38.7 | | | 117.4 | | | 106.7 | | Taxes Other Than Income Taxes | | 45.5 | | | 41.6 | | | 125.8 | | | 117.4 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 286.5 | | | 311.5 | | | 831.4 | | | 964.9 | | TOTAL EXPENSES | | 349.7 | | | 286.5 | | | 970.2 | | | 831.4 | |
| | | | | | | | | | | | | | | | | | |
OPERATING INCOME | OPERATING INCOME | | 146.1 | | | 120.5 | | | 363.9 | | | 292.2 | | OPERATING INCOME | | 159.2 | | | 146.1 | | | 434.2 | | | 363.9 | |
| | | | | | |
Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Interest Income | Interest Income | | 0.2 | | | 0.5 | | | 0.6 | | | 1.2 | | Interest Income | | 1.3 | | | 0.2 | | | 2.7 | | | 0.6 | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 9.2 | | | 4.4 | | | 16.7 | | | 14.4 | | Allowance for Equity Funds Used During Construction | | 5.2 | | | 9.2 | | | 13.2 | | | 16.7 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 2.8 | | | 2.8 | | | 8.3 | | | 8.4 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 4.2 | | | 2.8 | | | 12.5 | | | 8.3 | |
Interest Expense | Interest Expense | | (44.2) | | | (44.5) | | | (132.5) | | | (129.2) | | Interest Expense | | (55.4) | | | (44.2) | | | (153.2) | | | (132.5) | |
| | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 114.1 | | | 83.7 | | | 257.0 | | | 187.0 | | |
INCOME BEFORE INCOME TAX EXPENSE | | INCOME BEFORE INCOME TAX EXPENSE | | 114.5 | | | 114.1 | | | 309.4 | | | 257.0 | |
| | | | | | |
Income Tax Expense (Benefit) | | 14.6 | | | 1.1 | | | 31.6 | | | (10.1) | | |
Income Tax Expense | | Income Tax Expense | | 20.9 | | | 14.6 | | | 56.2 | | | 31.6 | |
| NET INCOME | NET INCOME | | $ | 99.5 | | | $ | 82.6 | | | $ | 225.4 | | | $ | 197.1 | | NET INCOME | | $ | 93.6 | | | $ | 99.5 | | | $ | 253.2 | | | $ | 225.4 | |
| The common stock of AEP Texas is wholly-owned by Parent. | The common stock of AEP Texas is wholly-owned by Parent. | The common stock of AEP Texas is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 99.5 | | | $ | 82.6 | | | $ | 225.4 | | | $ | 197.1 | | Net Income | | $ | 93.6 | | | $ | 99.5 | | | $ | 253.2 | | | $ | 225.4 | |
| | | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME, NET OF TAXES | OTHER COMPREHENSIVE INCOME, NET OF TAXES | | | | | OTHER COMPREHENSIVE INCOME, NET OF TAXES | | | | |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | 0.3 | | | 0.3 | | | 0.8 | | | 0.8 | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | — | | | — | | | 0.1 | | | 0.1 | | |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.2 and $0.2 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | 0.3 | | | 0.3 | | | 0.8 | | | 0.8 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | — | | | — | | | — | | | 0.1 | |
| TOTAL OTHER COMPREHENSIVE INCOME | TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 | | | 0.3 | | | 0.9 | | | 0.9 | | TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 | | | 0.3 | | | 0.8 | | | 0.9 | |
| TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | $ | 99.8 | | | $ | 82.9 | | | $ | 226.3 | | | $ | 198.0 | | TOTAL COMPREHENSIVE INCOME | | $ | 93.9 | | | $ | 99.8 | | | $ | 254.0 | | | $ | 226.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | | | 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 | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | | TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | | $ | 1,457.9 | | | $ | 1,757.0 | | | $ | (8.9) | | | $ | 3,206.0 | |
| | 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 | | |
| | Net Income | | 82.6 | | | 82.6 | | |
Other Comprehensive Income | | 0.3 | | | 0.3 | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020 | | $ | 1,457.9 | | | $ | 1,713.1 | | | $ | (11.9) | | | $ | 3,159.1 | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | | $ | 1,457.9 | | | $ | 1,757.0 | | | $ | (8.9) | | | $ | 3,206.0 | | |
| | Net Income | Net Income | | 46.1 | | | 46.1 | | Net Income | | 46.1 | | | 46.1 | |
Other Comprehensive Income | Other Comprehensive Income | | 0.3 | | | 0.3 | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | | 1,457.9 | | | 1,803.1 | | | (8.6) | | | 3,252.4 | | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | | 1,457.9 | | | 1,803.1 | | | (8.6) | | | 3,252.4 | |
| | Net Income | Net Income | | | | 79.8 | | | 79.8 | | Net Income | | | | 79.8 | | | | | 79.8 | |
Other Comprehensive Income | Other Comprehensive Income | | | | 0.3 | | | 0.3 | | Other Comprehensive Income | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | | 1,457.9 | | | 1,882.9 | | | (8.3) | | | 3,332.5 | | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | | 1,457.9 | | | 1,882.9 | | | (8.3) | | | 3,332.5 | |
| | Net Income | Net Income | | 99.5 | | | 99.5 | | Net Income | | 99.5 | | | 99.5 | |
Other Comprehensive Income | Other Comprehensive Income | | 0.3 | | | 0.3 | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | | $ | 1,457.9 | | | $ | 1,982.4 | | | $ | (8.0) | | | $ | 3,432.3 | | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | | $ | 1,457.9 | | | $ | 1,982.4 | | | $ | (8.0) | | | $ | 3,432.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | $ | 1,553.9 | | | $ | 2,046.8 | | | $ | (6.5) | | | $ | 3,594.2 | |
| | Net Income | | Net Income | | 69.6 | | | 69.6 | |
Other Comprehensive Income | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | 1,553.9 | | | 2,116.4 | | | (6.2) | | | 3,664.1 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.3 | | | 1.3 | |
Net Income | | Net Income | | | | 90.0 | | | 90.0 | |
Other Comprehensive Income | | Other Comprehensive Income | | | | 0.2 | | | 0.2 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022 | | 1,555.2 | | | 2,206.4 | | | (6.0) | | | 3,755.6 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 0.5 | | | 0.5 | |
Net Income | | Net Income | | 93.6 | | | 93.6 | |
Other Comprehensive Income | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022 | | $ | 1,555.7 | | | $ | 2,300.0 | | | $ | (5.7) | | | $ | 3,850.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 0.1 | | | $ | 0.1 | | Cash and Cash Equivalents | | $ | 0.1 | | | $ | 0.1 | |
Restricted Cash (September 30, 2021 and December 31, 2020 Amounts Include $43.9 and $28.7, Respectively, Related to Transition Funding and Restoration Funding) | | 43.9 | | | 28.7 | | |
Restricted Cash (September 30, 2022 and December 31, 2021 Amounts Include $47.7 and $30.4, Respectively, Related to Transition Funding and Restoration Funding) | | Restricted Cash (September 30, 2022 and December 31, 2021 Amounts Include $47.7 and $30.4, Respectively, Related to Transition Funding and Restoration Funding) | | 47.7 | | | 30.4 | |
Advances to Affiliates | Advances to Affiliates | | 54.6 | | | 7.1 | | Advances to Affiliates | | 136.3 | | | 6.9 | |
Accounts Receivable: | Accounts Receivable: | | | | Accounts Receivable: | | | |
Customers | Customers | | 142.1 | | | 112.8 | | Customers | | 166.0 | | | 123.4 | |
Affiliated Companies | Affiliated Companies | | 4.8 | | | 5.1 | | Affiliated Companies | | 5.9 | | | 7.9 | |
Accrued Unbilled Revenues | Accrued Unbilled Revenues | | 81.0 | | | 65.8 | | Accrued Unbilled Revenues | | 94.7 | | | 77.9 | |
| Miscellaneous | | Miscellaneous | | 0.2 | | | — | |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | | (4.1) | | | (0.1) | | Allowance for Uncollectible Accounts | | (4.1) | | | (4.0) | |
Total Accounts Receivable | Total Accounts Receivable | | 223.8 | | | 183.6 | | Total Accounts Receivable | | 262.7 | | | 205.2 | |
| Materials and Supplies | Materials and Supplies | | 72.5 | | | 70.0 | | Materials and Supplies | | 113.8 | | | 73.9 | |
| Risk Management Assets | | Risk Management Assets | | 0.2 | | | — | |
Accrued Tax Benefits | Accrued Tax Benefits | | 23.7 | | | 16.8 | | Accrued Tax Benefits | | 21.7 | | | 24.8 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 6.9 | | | 4.6 | | Prepayments and Other Current Assets | | 6.5 | | | 5.9 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 425.5 | | | 310.9 | | TOTAL CURRENT ASSETS | | 589.0 | | | 347.2 | |
| | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | Electric: | | | |
| Transmission | Transmission | | 5,627.1 | | | 5,279.6 | | Transmission | | 6,154.4 | | | 5,849.9 | |
Distribution | Distribution | | 4,823.7 | | | 4,580.8 | | Distribution | | 5,192.3 | | | 4,917.2 | |
Other Property, Plant and Equipment | Other Property, Plant and Equipment | | 944.3 | | | 868.4 | | Other Property, Plant and Equipment | | 1,013.6 | | | 961.1 | |
Construction Work in Progress | Construction Work in Progress | | 539.4 | | | 614.1 | | Construction Work in Progress | | 697.7 | | | 551.3 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 11,934.5 | | | 11,342.9 | | Total Property, Plant and Equipment | | 13,058.0 | | | 12,279.5 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 1,621.1 | | | 1,529.3 | | Accumulated Depreciation and Amortization | | 1,746.3 | | | 1,644.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 10,313.4 | | | 9,813.6 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 11,311.7 | | | 10,635.4 | |
| | | | | | | | | | |
OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 290.4 | | | 266.8 | | Regulatory Assets | | 243.9 | | | 275.2 | |
Securitized Assets (September 30, 2021 and December 31, 2020 Amounts Include $389.1 and $446.8, Respectively, Related to Transition Funding and Restoration Funding) | | 389.1 | | | 446.8 | | |
| Securitized Assets (September 30, 2022 and December 31, 2021 Amounts Include $308.3 and $367.6, Respectively, Related to Transition Funding and Restoration Funding) | | Securitized Assets (September 30, 2022 and December 31, 2021 Amounts Include $308.3 and $367.6, Respectively, Related to Transition Funding and Restoration Funding) | | 308.3 | | | 367.6 | |
Long-term Risk Management Assets | | Long-term Risk Management Assets | | 0.1 | | | — | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 213.1 | | | 192.1 | | Deferred Charges and Other Noncurrent Assets | | 237.0 | | | 211.3 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 892.6 | | | 905.7 | | TOTAL OTHER NONCURRENT ASSETS | | 789.3 | | | 854.1 | |
| | | | | | | | | | |
TOTAL ASSETS | TOTAL ASSETS | | $ | 11,631.5 | | | $ | 11,030.2 | | TOTAL ASSETS | | $ | 12,690.0 | | | $ | 11,836.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | — | | | $ | 67.1 | | Advances from Affiliates | | $ | — | | | $ | 26.9 | |
Accounts Payable: | Accounts Payable: | | | Accounts Payable: | | |
General | General | | 194.3 | | | 231.7 | | General | | 249.2 | | | 306.3 | |
Affiliated Companies | Affiliated Companies | | 29.4 | | | 44.0 | | Affiliated Companies | | 32.6 | | | 32.5 | |
| Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2021 and December 31, 2020 Amounts Include $90.1 and $88.7, Respectively, Related to Transition Funding and Restoration Funding) | | 315.1 | | | 88.7 | | |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $92.5 and $91, Respectively, Related to Transition Funding and Restoration Funding) | | Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $92.5 and $91, Respectively, Related to Transition Funding and Restoration Funding) | | 277.5 | | | 716.0 | |
| Accrued Taxes | Accrued Taxes | | 114.7 | | | 78.3 | | Accrued Taxes | | 129.6 | | | 93.3 | |
Accrued Interest (September 30, 2021 and December 31, 2020 Amounts Include $3 and $2.5, Respectively, Related to Transition Funding and Restoration Funding) | | 60.7 | | | 43.9 | | |
Accrued Interest (September 30, 2022 and December 31, 2021 Amounts Include $2.5 and $2.3, Respectively, Related to Transition Funding and Restoration Funding) | | Accrued Interest (September 30, 2022 and December 31, 2021 Amounts Include $2.5 and $2.3, Respectively, Related to Transition Funding and Restoration Funding) | | 72.3 | | | 44.7 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 14.1 | | | 14.5 | | Obligations Under Operating Leases | | 14.0 | | | 14.0 | |
| Other Current Liabilities | Other Current Liabilities | | 98.4 | | | 108.6 | | Other Current Liabilities | | 110.5 | | | 78.0 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 826.7 | | | 676.8 | | TOTAL CURRENT LIABILITIES | | 885.7 | | | 1,311.7 | |
| | | | | | | | | | |
NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated (September 30, 2021 and December 31, 2020 Amounts Include $350.9 and $403.9, Respectively, Related to Transition Funding and Restoration Funding) | | 4,901.0 | | | 4,731.7 | | |
| Long-term Debt – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $259.2 and $313.7, Respectively, Related to Transition Funding and Restoration Funding) | | Long-term Debt – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $259.2 and $313.7, Respectively, Related to Transition Funding and Restoration Funding) | | 5,416.4 | | | 4,464.8 | |
Long-term Risk Management Liabilities | | Long-term Risk Management Liabilities | | 0.1 | | | — | |
Deferred Income Taxes | Deferred Income Taxes | | 1,087.1 | | | 1,016.7 | | Deferred Income Taxes | | 1,132.2 | | | 1,088.9 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,256.8 | | | 1,270.8 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,258.3 | | | 1,242.0 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 64.5 | | | 71.0 | | Obligations Under Operating Leases | | 54.3 | | | 61.3 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 63.1 | | | 57.2 | | Deferred Credits and Other Noncurrent Liabilities | | 93.0 | | | 73.8 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 7,372.5 | | | 7,147.4 | | TOTAL NONCURRENT LIABILITIES | | 7,954.3 | | | 6,930.8 | |
| | | | | | | | | | |
TOTAL LIABILITIES | TOTAL LIABILITIES | | 8,199.2 | | | 7,824.2 | | TOTAL LIABILITIES | | 8,840.0 | | | 8,242.5 | |
| | | | | | | | | | |
Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | | |
| | | | | | |
COMMON SHAREHOLDER’S EQUITY | COMMON SHAREHOLDER’S EQUITY | | | | | COMMON SHAREHOLDER’S EQUITY | | | | |
Paid-in Capital | Paid-in Capital | | 1,457.9 | | | 1,457.9 | | Paid-in Capital | | 1,555.7 | | | 1,553.9 | |
Retained Earnings | Retained Earnings | | 1,982.4 | | | 1,757.0 | | Retained Earnings | | 2,300.0 | | | 2,046.8 | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | (8.0) | | | (8.9) | | Accumulated Other Comprehensive Income (Loss) | | (5.7) | | | (6.5) | |
TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,432.3 | | | 3,206.0 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,850.0 | | | 3,594.2 | |
| | | | | | | | | | |
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 11,631.5 | | | $ | 11,030.2 | | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 12,690.0 | | | $ | 11,836.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TEXAS INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 225.4 | | | $ | 197.1 | | Net Income | | $ | 253.2 | | | $ | 225.4 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | Depreciation and Amortization | | 287.1 | | | 435.8 | | Depreciation and Amortization | | 342.7 | | | 287.1 | |
Deferred Income Taxes | Deferred Income Taxes | | 45.8 | | | (11.5) | | Deferred Income Taxes | | 35.1 | | | 45.8 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (16.7) | | | (14.4) | | Allowance for Equity Funds Used During Construction | | (13.2) | | | (16.7) | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | — | | | 0.1 | | Mark-to-Market of Risk Management Contracts | | (0.2) | | | — | |
Pension Contributions to Qualified Plan Trust | | — | | | (11.3) | | |
| | Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | (73.4) | | | (77.3) | | Change in Other Noncurrent Assets | | (48.4) | | | (73.4) | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 17.5 | | | (30.0) | | Change in Other Noncurrent Liabilities | | 49.2 | | | 17.5 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | Changes in Certain Components of Working Capital: | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | (40.2) | | | (40.2) | | Accounts Receivable, Net | | (57.5) | | | (40.2) | |
Fuel, Materials and Supplies | | (2.5) | | | (9.4) | | |
Materials and Supplies | | Materials and Supplies | | (39.9) | | | (2.5) | |
Accounts Payable | Accounts Payable | | (10.9) | | | 24.2 | | Accounts Payable | | 16.0 | | | (10.9) | |
| Accrued Taxes, Net | Accrued Taxes, Net | | 29.5 | | | 73.4 | | Accrued Taxes, Net | | 39.4 | | | 29.5 | |
| Other Current Assets | Other Current Assets | | (2.0) | | | (0.8) | | Other Current Assets | | 1.0 | | | (2.0) | |
Other Current Liabilities | Other Current Liabilities | | (5.0) | | | (49.8) | | Other Current Liabilities | | 12.2 | | | (5.0) | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | | 454.6 | | | 485.9 | | Net Cash Flows from Operating Activities | | 589.6 | | | 454.6 | |
| | | | | | | | | | |
INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (742.4) | | | (976.1) | | Construction Expenditures | | (949.8) | | | (742.4) | |
Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | (47.5) | | | 58.8 | | Change in Advances to Affiliates, Net | | (129.4) | | | (47.5) | |
| Other Investing Activities | Other Investing Activities | | 29.6 | | | 24.1 | | Other Investing Activities | | 26.7 | | | 29.6 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (760.3) | | | (893.2) | | Net Cash Flows Used for Investing Activities | | (1,052.5) | | | (760.3) | |
| | | | | | | | | | |
FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Capital Contribution from Parent | | Capital Contribution from Parent | | 1.8 | | | — | |
Issuance of Long-term Debt – Nonaffiliated | | Issuance of Long-term Debt – Nonaffiliated | | 1,188.7 | | | 444.2 | |
| Issuance of Long-term Debt – Nonaffiliated | | 444.2 | | | 652.8 | | |
Change in Short-term Debt, Net – Nonaffiliated | | — | | | 2.0 | | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (67.1) | | | — | | Change in Advances from Affiliates, Net | | (26.9) | | | (67.1) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (52.2) | | | (356.5) | | Retirement of Long-term Debt – Nonaffiliated | | (678.6) | | | (52.2) | |
Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (5.0) | | | (4.7) | | Principal Payments for Finance Lease Obligations | | (5.1) | | | (5.0) | |
| Other Financing Activities | Other Financing Activities | | 1.0 | | | 0.8 | | Other Financing Activities | | 0.3 | | | 1.0 | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 320.9 | | | 294.4 | | Net Cash Flows from Financing Activities | | 480.2 | | | 320.9 | |
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | 15.2 | | | (112.9) | | |
Net Change in Cash, Cash Equivalents and Restricted Cash | | Net Change in Cash, Cash Equivalents and Restricted Cash | | 17.3 | | | 15.2 | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 28.8 | | | 157.8 | | Cash, Cash Equivalents and Restricted Cash at Beginning of Period | | 30.5 | | | 28.8 | |
Cash, Cash Equivalents and Restricted Cash at End of Period | Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 44.0 | | | $ | 44.9 | | Cash, Cash Equivalents and Restricted Cash at End of Period | | $ | 47.8 | | | $ | 44.0 | |
| | | | | | | | | | |
SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 110.0 | | | $ | 102.0 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 121.1 | | | $ | 110.0 | |
Net Cash Paid (Received) for Income Taxes | Net Cash Paid (Received) for Income Taxes | | (8.4) | | | (55.6) | | Net Cash Paid (Received) for Income Taxes | | 10.0 | | | (8.4) | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 3.3 | | | 5.1 | | Noncash Acquisitions Under Finance Leases | | 4.1 | | | 3.3 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 134.9 | | | 167.6 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 156.0 | | | 134.9 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
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 September 30, | | As of September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Plant In Service | Plant In Service | | $ | 10,851.9 | | | $ | 9,240.4 | | Plant In Service | | $ | 12,050.4 | | | $ | 10,851.9 | |
Construction Work in Progress | Construction Work in Progress | | 1,507.4 | | | 1,680.9 | | Construction Work in Progress | | 1,644.6 | | | 1,507.4 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 730.4 | | | 531.8 | | Accumulated Depreciation and Amortization | | 952.4 | | | 730.4 | |
Total Transmission Property, Net | Total Transmission Property, Net | | $ | 11,628.9 | | | $ | 10,389.5 | | Total Transmission Property, Net | | $ | 12,742.6 | | | $ | 11,628.9 | |
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
AEP Transmission Company, LLC and Subsidiaries |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 117.6145.4 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 72.941.5 | |
Total Change in Transmission Revenues | | 72.941.5 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (9.2)(5.7) | |
Depreciation and Amortization | | (14.5)(11.4) | |
Taxes Other Than Income Taxes | | (8.8)(7.7) | |
Interest Income | | 0.5 | |
Allowance for Equity Funds Used During Construction | | (4.2)4.3 | |
Interest Expense | | (3.4)(6.6) | |
Total Change in Expenses and Other | | (40.1)(26.6) | |
| | |
Income Tax Expense | | (5.0)(7.6) | |
| | |
| | |
Third Quarter of 20212022 | | $ | 145.4152.7 | |
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:
•Transmission Revenues increased $73$42 million primarily due to continued investment in transmission assets.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $9$6 million primarily due to the following:
•A $2 million increase in vegetation management expenses.
•A $2 million increase in an accrual for NERC compliance costs.
•A $2 million increase in employee-related expenses.
•A $1 million increase in rent expense.cancelled capital projects.
•Depreciation and Amortization expenses increased $15$11 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $9$8 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During Construction decreasedincreased $4 million primarily due to lowerhigher CWIP.
•Interest Expense increased $3$7 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $5$8 million primarily due to an increase in pretax book income.income and a decrease in parent company loss benefit.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
AEP Transmission Company, LLC and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 20202021 | | $ | 309.1445.7 | |
| | |
Changes in Transmission Revenues: | | |
Transmission Revenues | | 266.479.1 | |
Total Change in Transmission Revenues | | 266.479.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (11.6)(15.5) | |
Depreciation and Amortization | | (42.6)(37.2) | |
Taxes Other Than Income Taxes | | (26.1)(24.1) | |
Interest Income | | (1.9)0.6 | |
Allowance for Equity Funds Used During Construction | | (5.6)1.9 | |
Interest Expense | | (9.4)(15.2) | |
Total Change in Expenses and Other | | (97.2)(89.5) | |
| | |
Income Tax Expense | | (32.6)(8.7) | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 445.7426.6 | |
The major components of the increase in transmission revenues, which consists of wholesale sales to affiliates and nonaffiliates were as follows:
•Transmission Revenues increased $266$79 million primarily due to the following:
•A $204$122 million increase due to continued investment in transmission assets.
This increase was partially offset by:
•A $45$30 million increase as a result ofdecrease due to the affiliated annual transmission formula rate true-up which istrue-up. This decrease was offset in Other Operation and Maintenance expense across the other Registrant Subsidiaries.
•A $14$13 million increase as a result ofdecrease due to the non-affiliated annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $12$16 million primarily due to the following:
•A $4$12 million increase in vegetation managementemployee-related expenses.
•A $2$5 million increase in an accrual for NERC compliance costs.
•A $2 million increase in rent expense.
•A $1 million increase in property insurance premiums.due to cancelled capital projects.
•Depreciation and Amortization expenses increased $43$37 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $26$24 million primarily due to higher property taxes as a result of increased transmission investment.
•Allowance for Equity Funds Used During ConstructionInterest Expense decreased $6increased $15 million primarily due to lower CWIP.higher long-term debt balances.
•InterestIncome Tax Expense increased $9 million primarily due to higher long-term debt balances.
•Income Tax Expense increased $33 million primarily due to an increasea decrease in parent company loss benefit, partially offset by a decrease in pretax book income.
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Transmission Revenues | Transmission Revenues | | $ | 79.2 | | | $ | 62.9 | | | $ | 239.3 | | | $ | 184.6 | | Transmission Revenues | | $ | 89.1 | | | $ | 79.2 | | | $ | 261.7 | | | $ | 241.6 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 297.6 | | | 241.2 | | | 864.6 | | | 652.6 | | Sales to AEP Affiliates | | 340.6 | | | 297.7 | | | 999.5 | | | 882.3 | |
Provision for Refund – Affiliated | | Provision for Refund – Affiliated | | (9.3) | | | (0.1) | | | (65.7) | | | (17.7) | |
Provision for Refund – Nonaffiliated | | Provision for Refund – Nonaffiliated | | (1.9) | | | — | | | (12.2) | | | (2.3) | |
Other Revenues | Other Revenues | | 0.2 | | | — | | | 0.3 | | | 0.6 | | Other Revenues | | — | | | 0.2 | | | — | | | 0.3 | |
TOTAL REVENUES | TOTAL REVENUES | | 377.0 | | | 304.1 | | | 1,104.2 | | | 837.8 | | TOTAL REVENUES | | 418.5 | | | 377.0 | | | 1,183.3 | | | 1,104.2 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Other Operation | Other Operation | | 32.6 | | | 25.3 | | | 78.1 | | | 72.0 | | Other Operation | | 39.6 | | | 32.6 | | | 94.7 | | | 78.1 | |
Maintenance | Maintenance | | 5.4 | | | 3.5 | | | 12.3 | | | 6.8 | | Maintenance | | 4.1 | | | 5.4 | | | 11.2 | | | 12.3 | |
Depreciation and Amortization | Depreciation and Amortization | | 76.0 | | | 61.5 | | | 219.0 | | | 176.4 | | Depreciation and Amortization | | 87.4 | | | 76.0 | | | 256.2 | | | 219.0 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 61.0 | | | 52.2 | | | 178.9 | | | 152.8 | | Taxes Other Than Income Taxes | | 68.7 | | | 61.0 | | | 203.0 | | | 178.9 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 175.0 | | | 142.5 | | | 488.3 | | | 408.0 | | TOTAL EXPENSES | | 199.8 | | | 175.0 | | | 565.1 | | | 488.3 | |
| OPERATING INCOME | OPERATING INCOME | | 202.0 | | | 161.6 | | | 615.9 | | | 429.8 | | OPERATING INCOME | | 218.7 | | | 202.0 | | | 618.2 | | | 615.9 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Interest Income - Affiliated | Interest Income - Affiliated | | 0.2 | | | 0.2 | | | 0.4 | | | 2.3 | | Interest Income - Affiliated | | 0.7 | | | 0.2 | | | 1.0 | | | 0.4 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 16.0 | | | 20.2 | | | 49.3 | | | 54.9 | | Allowance for Equity Funds Used During Construction | | 20.3 | | | 16.0 | | | 51.2 | | | 49.3 | |
| Interest Expense | Interest Expense | | (36.1) | | | (32.7) | | | (104.5) | | | (95.1) | | Interest Expense | | (42.7) | | | (36.1) | | | (119.7) | | | (104.5) | |
| INCOME BEFORE INCOME TAX EXPENSE | INCOME BEFORE INCOME TAX EXPENSE | | 182.1 | | | 149.3 | | | 561.1 | | | 391.9 | | INCOME BEFORE INCOME TAX EXPENSE | | 197.0 | | | 182.1 | | | 550.7 | | | 561.1 | |
| Income Tax Expense | Income Tax Expense | | 36.7 | | | 31.7 | | | 115.4 | | | 82.8 | | Income Tax Expense | | 44.3 | | | 36.7 | | | 124.1 | | | 115.4 | |
| NET INCOME | NET INCOME | | $ | 145.4 | | | $ | 117.6 | | | $ | 445.7 | | | $ | 309.1 | | NET INCOME | | $ | 152.7 | | | $ | 145.4 | | | $ | 426.6 | | | $ | 445.7 | |
| AEPTCo is wholly-owned by AEP Transmission Holdco. | AEPTCo is wholly-owned by AEP Transmission Holdco. | AEPTCo is wholly-owned by AEP Transmission Holdco. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(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 | | |
| | Net Income | | | 117.6 | | | 117.6 | | |
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2020 | | $ | 2,665.6 | | | $ | 1,833.0 | | | $ | 4,498.6 | | |
| | | | | | | | | | Paid-in Capital | | Retained Earnings | | Total |
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020 | TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020 | | $ | 2,765.6 | | | $ | 1,947.3 | | | $ | 4,712.9 | | TOTAL MEMBER'S EQUITY – DECEMBER 31, 2020 | | $ | 2,765.6 | | | $ | 1,947.3 | | | $ | 4,712.9 | |
| | | | |
Capital Contribution from Member | Capital Contribution from Member | | 124.0 | | | 124.0 | | Capital Contribution from Member | | 124.0 | | | 124.0 | |
Net Income | Net Income | | 151.7 | | | 151.7 | | Net Income | | | | 151.7 | | | 151.7 | |
TOTAL MEMBER'S EQUITY – MARCH 31, 2021 | TOTAL MEMBER'S EQUITY – MARCH 31, 2021 | | 2,889.6 | | | 2,099.0 | | | 4,988.6 | | TOTAL MEMBER'S EQUITY – MARCH 31, 2021 | | 2,889.6 | | | 2,099.0 | | | 4,988.6 | |
| | | | |
Capital Contribution from Member | Capital Contribution from Member | | 60.0 | | | 60.0 | | Capital Contribution from Member | | 60.0 | | | 60.0 | |
| Net Income | Net Income | | 148.6 | | | 148.6 | | Net Income | | 148.6 | | | 148.6 | |
TOTAL MEMBER'S EQUITY – JUNE 30, 2021 | TOTAL MEMBER'S EQUITY – JUNE 30, 2021 | | 2,949.6 | | | 2,247.6 | | | 5,197.2 | | TOTAL MEMBER'S EQUITY – JUNE 30, 2021 | | 2,949.6 | | | 2,247.6 | | | 5,197.2 | |
| | Dividends Paid to Member | Dividends Paid to Member | | (112.5) | | | (112.5) | | Dividends Paid to Member | | (112.5) | | | (112.5) | |
Net Income | Net Income | | | | 145.4 | | | 145.4 | | Net Income | | | 145.4 | | | 145.4 | |
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2021 | TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2021 | | $ | 2,949.6 | | | $ | 2,280.5 | | | $ | 5,230.1 | | TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2021 | | $ | 2,949.6 | | | $ | 2,280.5 | | | $ | 5,230.1 | |
| | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 | | TOTAL MEMBER'S EQUITY – DECEMBER 31, 2021 | | $ | 2,949.6 | | | $ | 2,426.5 | | | $ | 5,376.1 | |
| | Dividends Paid to Member | | Dividends Paid to Member | | (40.0) | | | (40.0) | |
Net Income | | Net Income | | 155.4 | | | 155.4 | |
TOTAL MEMBER'S EQUITY – MARCH 31, 2022 | | TOTAL MEMBER'S EQUITY – MARCH 31, 2022 | | 2,949.6 | | | 2,541.9 | | | 5,491.5 | |
| | | | |
Capital Contribution from Member | | Capital Contribution from Member | | 2.8 | | | 2.8 | |
Dividends Paid to Member | | Dividends Paid to Member | | (50.0) | | | (50.0) | |
Net Income | | Net Income | | 118.5 | | | 118.5 | |
TOTAL MEMBER'S EQUITY – JUNE 30, 2022 | | TOTAL MEMBER'S EQUITY – JUNE 30, 2022 | | 2,952.4 | | | 2,610.4 | | | 5,562.8 | |
| Capital Contribution from Member | | Capital Contribution from Member | | 61.4 | | | 61.4 | |
Dividends Paid to Member | | Dividends Paid to Member | | (40.0) | | | (40.0) | |
Net Income | | Net Income | | | | 152.7 | | | 152.7 | |
TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2022 | | TOTAL MEMBER'S EQUITY – SEPTEMBER 30, 2022 | | $ | 3,013.8 | | | $ | 2,723.1 | | | $ | 5,736.9 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Advances to Affiliates | Advances to Affiliates | | $ | 79.2 | | | $ | 109.1 | | Advances to Affiliates | | $ | 106.7 | | | $ | 27.2 | |
Accounts Receivable: | Accounts Receivable: | | | Accounts Receivable: | | |
Customers | Customers | | 31.0 | | | 22.9 | | Customers | | 73.8 | | | 22.5 | |
Affiliated Companies | Affiliated Companies | | 96.7 | | | 81.2 | | Affiliated Companies | | 111.0 | | | 96.1 | |
| Total Accounts Receivable | Total Accounts Receivable | | 127.7 | | | 104.1 | | Total Accounts Receivable | | 184.8 | | | 118.6 | |
Materials and Supplies | Materials and Supplies | | 9.0 | | | 8.5 | | Materials and Supplies | | 11.7 | | | 9.3 | |
| Accrued Tax Benefits | | Accrued Tax Benefits | | 12.3 | | | 5.6 | |
Assets Held for Sale | | Assets Held for Sale | | 173.7 | | | 167.9 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 3.5 | | | 14.1 | | Prepayments and Other Current Assets | | 3.8 | | | 2.7 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 219.4 | | | 235.8 | | TOTAL CURRENT ASSETS | | 493.0 | | | 331.3 | |
| | | | | | | | | | |
TRANSMISSION PROPERTY | TRANSMISSION PROPERTY | | | | | TRANSMISSION PROPERTY | | | | |
Transmission Property | Transmission Property | | 10,458.4 | | | 9,593.5 | | Transmission Property | | 11,609.8 | | | 10,886.3 | |
Other Property, Plant and Equipment | Other Property, Plant and Equipment | | 393.5 | | | 329.5 | | Other Property, Plant and Equipment | | 440.6 | | | 427.4 | |
Construction Work in Progress | Construction Work in Progress | | 1,507.4 | | | 1,422.6 | | Construction Work in Progress | | 1,644.6 | | | 1,394.8 | |
Total Transmission Property | Total Transmission Property | | 12,359.3 | | | 11,345.6 | | Total Transmission Property | | 13,695.0 | | | 12,708.5 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 730.4 | | | 572.8 | | Accumulated Depreciation and Amortization | | 952.4 | | | 772.8 | |
TOTAL TRANSMISSION PROPERTY – NET | TOTAL TRANSMISSION PROPERTY – NET | | 11,628.9 | | | 10,772.8 | | TOTAL TRANSMISSION PROPERTY – NET | | 12,742.6 | | | 11,935.7 | |
| | | | | | | | | | |
OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
| Regulatory Assets | Regulatory Assets | | 10.1 | | | 15.1 | | Regulatory Assets | | 2.6 | | | 8.5 | |
Deferred Property Taxes | Deferred Property Taxes | | 66.1 | | | 220.1 | | Deferred Property Taxes | | 75.7 | | | 245.7 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 6.6 | | | 2.2 | | Deferred Charges and Other Noncurrent Assets | | 5.3 | | | 3.2 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 82.8 | | | 237.4 | | TOTAL OTHER NONCURRENT ASSETS | | 83.6 | | | 257.4 | |
| | | | | | | | | | |
TOTAL ASSETS | TOTAL ASSETS | | $ | 11,931.1 | | | $ | 11,246.0 | | TOTAL ASSETS | | $ | 13,319.2 | | | $ | 12,524.4 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER’S EQUITY
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | 13.9 | | | $ | 156.7 | | Advances from Affiliates | | $ | 61.0 | | | $ | 124.0 | |
Accounts Payable: | Accounts Payable: | | | | Accounts Payable: | | | |
General | General | | 298.8 | | | 380.4 | | General | | 332.1 | | | 460.1 | |
Affiliated Companies | Affiliated Companies | | 67.6 | | | 97.3 | | Affiliated Companies | | 121.5 | | | 69.9 | |
| Long-term Debt Due Within One Year – Nonaffiliated | Long-term Debt Due Within One Year – Nonaffiliated | | 50.0 | | | 50.0 | | Long-term Debt Due Within One Year – Nonaffiliated | | 104.0 | | | 104.0 | |
Accrued Taxes | Accrued Taxes | | 269.5 | | | 418.1 | | Accrued Taxes | | 293.0 | | | 479.0 | |
Accrued Interest | Accrued Interest | | 50.2 | | | 23.9 | | Accrued Interest | | 56.0 | | | 28.4 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 0.9 | | | 1.2 | | Obligations Under Operating Leases | | 1.3 | | | 0.9 | |
Liabilities Held for Sale | | Liabilities Held for Sale | | 27.6 | | | 27.6 | |
Other Current Liabilities | Other Current Liabilities | | 8.1 | | | 9.9 | | Other Current Liabilities | | 14.8 | | | 3.0 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 759.0 | | | 1,137.5 | | TOTAL CURRENT LIABILITIES | | 1,011.3 | | | 1,296.9 | |
| | | | | | | | | | |
NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 4,343.4 | | | 3,898.5 | | Long-term Debt – Nonaffiliated | | 4,782.6 | | | 4,239.9 | |
Deferred Income Taxes | Deferred Income Taxes | | 955.2 | | | 906.9 | | Deferred Income Taxes | | 1,032.8 | | | 962.9 | |
Regulatory Liabilities | Regulatory Liabilities | | 633.9 | | | 581.8 | | Regulatory Liabilities | | 698.2 | | | 644.1 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 1.0 | | | 0.4 | | Obligations Under Operating Leases | | 1.8 | | | 1.3 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 8.5 | | | 8.0 | | Deferred Credits and Other Noncurrent Liabilities | | 55.6 | | | 3.2 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 5,942.0 | | | 5,395.6 | | TOTAL NONCURRENT LIABILITIES | | 6,571.0 | | | 5,851.4 | |
| | | | | | | | | | |
TOTAL LIABILITIES | TOTAL LIABILITIES | | 6,701.0 | | | 6,533.1 | | TOTAL LIABILITIES | | 7,582.3 | | | 7,148.3 | |
| | | | | | | | | | |
Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | | |
| | | | | | |
MEMBER’S EQUITY | MEMBER’S EQUITY | | | | | MEMBER’S EQUITY | | | | |
Paid-in Capital | Paid-in Capital | | 2,949.6 | | | 2,765.6 | | Paid-in Capital | | 3,013.8 | | | 2,949.6 | |
Retained Earnings | Retained Earnings | | 2,280.5 | | | 1,947.3 | | Retained Earnings | | 2,723.1 | | | 2,426.5 | |
TOTAL MEMBER’S EQUITY | TOTAL MEMBER’S EQUITY | | 5,230.1 | | | 4,712.9 | | TOTAL MEMBER’S EQUITY | | 5,736.9 | | | 5,376.1 | |
| | | | | | | | | | |
TOTAL LIABILITIES AND MEMBER’S EQUITY | TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 11,931.1 | | | $ | 11,246.0 | | TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 13,319.2 | | | $ | 12,524.4 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
AEP TRANSMISSION COMPANY, LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 445.7 | | | $ | 309.1 | | Net Income | | $ | 426.6 | | | $ | 445.7 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | |
Depreciation and Amortization | Depreciation and Amortization | | 219.0 | | | 176.4 | | Depreciation and Amortization | | 256.2 | | | 219.0 | |
Deferred Income Taxes | Deferred Income Taxes | | 46.8 | | | 65.4 | | Deferred Income Taxes | | 60.6 | | | 46.8 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (49.3) | | | (54.9) | | Allowance for Equity Funds Used During Construction | | (51.2) | | | (49.3) | |
Property Taxes | Property Taxes | | 154.0 | | | 136.3 | | Property Taxes | | 170.0 | | | 154.0 | |
| Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | 2.3 | | | (1.5) | | Change in Other Noncurrent Assets | | 4.0 | | | 2.3 | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 8.3 | | | 19.5 | | Change in Other Noncurrent Liabilities | | 55.0 | | | 8.3 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | Changes in Certain Components of Working Capital: | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | (23.6) | | | (30.1) | | Accounts Receivable, Net | | (66.4) | | | (23.6) | |
Materials and Supplies | Materials and Supplies | | (0.5) | | | 0.2 | | Materials and Supplies | | (2.4) | | | (0.5) | |
Accounts Payable | Accounts Payable | | (10.7) | | | 26.0 | | Accounts Payable | | 53.1 | | | (10.7) | |
Accrued Taxes, Net | Accrued Taxes, Net | | (138.8) | | | (139.0) | | Accrued Taxes, Net | | (194.0) | | | (138.8) | |
Accrued Interest | | 26.3 | | | 29.0 | | |
| Other Current Assets | Other Current Assets | | 0.5 | | | 9.1 | | Other Current Assets | | (1.2) | | | 0.5 | |
Other Current Liabilities | Other Current Liabilities | | (3.6) | | | (10.7) | | Other Current Liabilities | | 27.2 | | | 22.7 | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | | 676.4 | | | 534.8 | | Net Cash Flows from Operating Activities | | 737.5 | | | 676.4 | |
| | | | | | | | | | |
INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (1,070.8) | | | (1,163.8) | | Construction Expenditures | | (1,059.3) | | | (1,070.8) | |
Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | 29.9 | | | (21.3) | | Change in Advances to Affiliates, Net | | (84.1) | | | 29.9 | |
| Other Investing Activities | Other Investing Activities | | (7.9) | | | 1.1 | | Other Investing Activities | | (5.3) | | | (7.9) | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (1,048.8) | | | (1,184.0) | | Net Cash Flows Used for Investing Activities | | (1,148.7) | | | (1,048.8) | |
| | | | | | | | | | |
FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | FINANCING ACTIVITIES | | | |
Capital Contributions from Member | | 184.0 | | | 185.0 | | |
Capital Contribution from Member | | Capital Contribution from Member | | 64.2 | | | 184.0 | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 443.7 | | | 519.4 | | Issuance of Long-term Debt – Nonaffiliated | | 540.9 | | | 443.7 | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (142.8) | | | (50.2) | | Change in Advances from Affiliates, Net | | (63.9) | | | (142.8) | |
Dividends Paid to Member | Dividends Paid to Member | | (112.5) | | | (5.0) | | Dividends Paid to Member | | (130.0) | | | (112.5) | |
| Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 372.4 | | | 649.2 | | Net Cash Flows from Financing Activities | | 411.2 | | | 372.4 | |
| | | | | | | | | | |
Net Change in Cash and Cash Equivalents | Net Change in Cash and Cash Equivalents | | — | | | — | | Net Change in Cash and Cash Equivalents | | — | | | — | |
Cash and Cash Equivalents at Beginning of Period | Cash and Cash Equivalents at Beginning of Period | | — | | | — | | Cash and Cash Equivalents at Beginning of Period | | — | | | — | |
Cash and Cash Equivalents at End of Period | Cash and Cash Equivalents at End of Period | | $ | — | | | $ | — | | Cash and Cash Equivalents at End of Period | | $ | — | | | $ | — | |
| | | | | | | | | | |
SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 75.8 | | | $ | 63.3 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 88.6 | | | $ | 75.8 | |
Net Cash Paid for Income Taxes | Net Cash Paid for Income Taxes | | 37.6 | | | 1.9 | | Net Cash Paid for Income Taxes | | 53.2 | | | 37.6 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 206.8 | | | 283.6 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 240.5 | | | 206.8 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | Retail: | | | | | | | |
Residential | Residential | 2,657 | | | 2,772 | | | 8,524 | | | 8,229 | | Residential | 2,553 | | | 2,657 | | | 8,308 | | | 8,524 | |
Commercial | Commercial | 1,596 | | | 1,612 | | | 4,483 | | | 4,410 | | Commercial | 1,566 | | | 1,596 | | | 4,545 | | | 4,483 | |
Industrial | Industrial | 2,223 | | | 2,193 | | | 6,590 | | | 6,507 | | Industrial | 2,211 | | | 2,223 | | | 6,655 | | | 6,590 | |
Miscellaneous | Miscellaneous | 206 | | | 203 | | | 602 | | | 585 | | Miscellaneous | 206 | | | 206 | | | 624 | | | 602 | |
Total Retail | Total Retail | 6,682 | | | 6,780 | | | 20,199 | | | 19,731 | | Total Retail | 6,536 | | | 6,682 | | | 20,132 | | | 20,199 | |
| Wholesale | Wholesale | 1,414 | | | 1,187 | | | 3,636 | | | 2,894 | | Wholesale | 644 | | | 1,414 | | | 1,269 | | | 3,636 | |
| Total KWhs | Total KWhs | 8,096 | | | 7,967 | | | 23,835 | | | 22,625 | | Total KWhs | 7,180 | | | 8,096 | | | 21,401 | | | 23,835 | |
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | — | | | 1 | | | 1,397 | | | 1,098 | | Actual – Heating (a) | 4 | | | — | | | 1,372 | | | 1,397 | |
Normal – Heating (b) | Normal – Heating (b) | 2 | | | 2 | | | 1,404 | | | 1,413 | | Normal – Heating (b) | 2 | | | 2 | | | 1,410 | | | 1,404 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 945 | | | 988 | | | 1,330 | | | 1,354 | | Actual – Cooling (c) | 876 | | | 945 | | | 1,299 | | | 1,330 | |
Normal – Cooling (b) | Normal – Cooling (b) | 831 | | | 825 | | | 1,214 | | | 1,208 | | Normal – Cooling (b) | 832 | | | 831 | | | 1,210 | | | 1,214 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Appalachian Power Company and Subsidiaries |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
|
Third Quarter of 20202021 | | $ | 116.686.3 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 40.710.6 | |
Margins from Off-system Sales | | 0.53.4 | |
Transmission Revenues | | 7.73.4 | |
Other Revenues | | (0.3)2.7 | |
Total Change in Gross Margin | | 48.620.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (53.8)(9.2) | |
Asset Impairments and Other Related Charges - Coal Fired Generation | | (24.9) | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | 37.0 | |
Depreciation and Amortization | | (12.2)(7.5) | |
Taxes Other Than Income Taxes | | (1.0)(1.7) | |
Interest Income | | (0.4)2.4 | |
| | |
Allowance for Equity Funds Used During Construction | | (2.4)(2.1) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.6 | |
Interest Expense | | 2.2 (8.9) | |
Total Change in Expenses and Other | | (67.6)(12.3) | |
| | |
Income Tax Expense | | (11.3)(1.4) | |
| | |
Third Quarter of 20212022 | | $ | 86.392.7 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased $41$11 million primarily due to the following:
•A $40$20 million increase due to rider revenues primarily in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $10 million increase due to lower customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.by:
•A $6 million increasedecrease in weather-normalized margins primarily driven by an increase in the industrial class, partially offset by a decreasedecreases in the residential class.
These increases were partially offset by:
•An $11 million decrease in deferred fuel primarily due to the timing of expenses recovered through the Expanded Net Energy Cost (ENEC). This decrease was offset in expense items below.and industrial classes.
•A $4$5 million decrease in weather-related usage primarily driven by a 4%7% decrease in cooling degree days.
•Margins from Off-System Sales increased $3 million primarily due to increased generation and strong market pricing.
•Transmission Revenues increased $8$3 million primarily due to an increasecontinued investment in transmission investment. This increase was partially offset in Depreciation and Amortization expenses below.assets.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $54$9 million primarily due to the following:
•A $33$6 million increase in recoverable PJM transmissiondistribution expenses primarily due to storm restoration expenses.
•A $2 million increase in renewable energy credits and compliance expenses associated with the Virginia Clean Economy Act. This increase was partially offset in Retail Margins above.
•A $13Asset Impairments and Other Related Charges - Coal Fired Generation increased $25 million increasedue to a write-off of a regulatory asset in vegetation management expenses. This increase was partially offsetaccordance with the August 2022 Virginia Supreme Court opinion related to the 2017-2019 Virginia Triennial Review.
•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million due to the establishment of a regulatory asset in Retail Margins above.accordance with the August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $12$8 million primarily due to an increase in depreciation rates in Virginia and a higher depreciable base. This increase was partially offset in Retail Margins
•Interest Expense increased $9 million primarily due to higher long-term debt balances and Transmission Revenues above.higher interest rates.
•Income Tax Expense increased $11 million primarily due to a decrease in amortization of Excess ADIT. This increase was partially offset in Retail Margins above.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Appalachian Power Company and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Net Income |
(in millions) |
|
Nine Months Ended September 30, 20202021 | | $ | 313.2275.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 103.0130.2 | |
Margins from Off-system Sales | | 2.8 (0.6) | |
Transmission Revenues | | 21.921.1 | |
Other Revenues | | (1.2)7.2 | |
Total Change in Gross Margin | | 126.5157.9 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (98.7)(102.1) | |
Asset Impairments and Other Related Charges - Coal Fired Generation | | (24.9) | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | 37.0 | |
Depreciation and Amortization | | (40.6)(24.4) | |
Taxes Other Than Income Taxes | | (2.5)(4.3) | |
Interest Income | | (0.6)2.2 | |
| | |
Allowance for Equity Funds Used During Construction | | 0.6 (5.3) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.17.6 | |
Interest Expense | | 1.6 (10.5) | |
Total Change in Expenses and Other | | (140.1)(124.7) | |
| | |
Income Tax Expense | | (24.5)(5.2) | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 275.1303.1 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased $103$130 million primarily due to the following:
•A $63$104 million increase due to rider revenues in Virginia and West Virginia. This increase was partially offset in other expense items below.
•A $30 million increase in weather-related usage primarily driven by a 27% increase in heating degree days.
•A $10 million increase in weather-normalized margins primarily driven by increases in the commercial and industrial classes, partially offset by a decrease in the residential class.
•A $9An $18 million increase due to lower customer refunds related to Tax Reform. This increase was partially offset in Income Tax Expense below.
•A $13 million increase in weather-normalized margins primarily driven by increases in the residential and commercial classes.
These increases were partially offset by:
•A $7$6 million decrease in deferred fuelweather-related usage primarily due to the timing of expenses recovered through the ENEC. Thisdriven by a 2% decrease was offset in expense items below.cooling degree days and a 2% decrease in heating degree days.
•Transmission Revenues increased $22$21 million primarily due to anthe following:
•An $11 million increase due to continued investment in transmission investment.assets.
•A $10 million increase due to transmission formula rate true-up activity.
•Other Revenues increased $7 million primarily due to business development revenue. This increase was partially offset in DepreciationOther Operation and AmortizationMaintenance expenses below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $99$102 million primarily due to the following:
•A $44$63 million increase in transmission expenses primarily due to an $80 million increase in recoverable PJM expenses, partially offset by an $11 million decrease in transmission expenses. This increase was partiallyformula rate true-up activity. These items were primarily offset in Retail Margins above.
•A $40$24 million increase in vegetation management expenses. This increase was partially offset in Retail Margins above.maintenance expenses at various generation plants.
•A $13$16 million increase in PJM transmissiondistribution expenses as a result of the annual transmission formula rate true-up. This increase was partially offset in Retail Margins above.primarily related to storm restoration costs.
•A $7 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.in employee-related expenses.
These increases were partially offset by:
•A $6$13 million decrease due to gains from the sale of land in distribution expenses2022.
•Asset Impairments and Other Related Charges - Coal Fired Generation increased $25 million due to a write-off of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion related to storm restoration costs.the 2017-2019 Virginia Triennial Review.
•Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset increased $37 million due to the establishment of a regulatory asset in accordance with the August 2022 Virginia Supreme Court opinion and resulting under-earning during the 2017-2019 Triennial Review.
•Depreciation and Amortization expenses increased $41$24 million primarily due to a higher depreciable base.
•Taxes Other Than Income Taxes increased $4 million primarily due to an increase in depreciation ratesproperty taxes driven by additional investments in Virginiatransmission and distribution assets and higher tax rates.
•Allowance for Equity Funds Used During Construction decreased $5 million primarily due to a lower AFUDC base and a decrease in AFUDC equity rates.
•Non-Service Cost Components of Net Periodic Benefit Cost decreased $8 million primarily due to an increase in discount rates, an increase in the expected return on plan assets and favorable plan returns in 2021.
•Interest Expense increased $11 million primarily due to higher depreciable base. This increase was partially offset in Retail Marginslong-term debt balances and Transmission Revenues above.higher interest rates.
•Income Tax Expense increased $25$5 million primarily due to an increase in pretax book income and a decrease in amortization of Excess ADIT. This increaseADIT, partially offset by a decrease in state taxes and a favorable one-time adjustment recognized in 2022. The decrease in amortization of Excess ADIT was partially offset in Retail Margins above.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | Electric Generation, Transmission and Distribution | | $ | 748.5 | | | $ | 688.9 | | | $ | 2,149.2 | | | $ | 1,989.9 | | Electric Generation, Transmission and Distribution | | $ | 818.4 | | | $ | 748.5 | | | $ | 2,370.4 | | | $ | 2,149.2 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 52.4 | | | 44.4 | | | 140.6 | | | 124.9 | | Sales to AEP Affiliates | | 67.6 | | | 52.4 | | | 187.6 | | | 140.6 | |
Other Revenues | Other Revenues | | 3.1 | | | 2.4 | | | 8.2 | | | 7.8 | | Other Revenues | | 2.9 | | | 3.1 | | | 11.8 | | | 8.2 | |
TOTAL REVENUES | TOTAL REVENUES | | 804.0 | | | 735.7 | | | 2,298.0 | | | 2,122.6 | | TOTAL REVENUES | | 888.9 | | | 804.0 | | | 2,569.8 | | | 2,298.0 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 170.8 | | | 166.0 | | | 471.9 | | | 430.9 | | |
Purchased Electricity for Resale | | 82.4 | | | 67.5 | | | 248.4 | | | 240.5 | | |
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 318.0 | | | 253.2 | | | 834.2 | | | 720.3 | |
| | Other Operation | Other Operation | | 173.0 | | | 136.3 | | | 442.1 | | | 379.1 | | Other Operation | | 182.0 | | | 173.0 | | | 514.0 | | | 442.1 | |
Maintenance | Maintenance | | 69.1 | | | 52.0 | | | 184.4 | | | 148.7 | | Maintenance | | 69.3 | | | 69.1 | | | 214.6 | | | 184.4 | |
Asset Impairments and Other Related Charges - Coal Fired Generation | | Asset Impairments and Other Related Charges - Coal Fired Generation | | 24.9 | | | — | | | 24.9 | | | — | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | (37.0) | | | — | | | (37.0) | | | — | |
Depreciation and Amortization | Depreciation and Amortization | | 135.4 | | | 123.2 | | | 406.6 | | | 366.0 | | Depreciation and Amortization | | 142.9 | | | 135.4 | | | 431.0 | | | 406.6 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 39.8 | | | 38.8 | | | 116.7 | | | 114.2 | | Taxes Other Than Income Taxes | | 41.5 | | | 39.8 | | | 121.0 | | | 116.7 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 670.5 | | | 583.8 | | | 1,870.1 | | | 1,679.4 | | TOTAL EXPENSES | | 741.6 | | | 670.5 | | | 2,102.7 | | | 1,870.1 | |
| OPERATING INCOME | OPERATING INCOME | | 133.5 | | | 151.9 | | | 427.9 | | | 443.2 | | OPERATING INCOME | | 147.3 | | | 133.5 | | | 467.1 | | | 427.9 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Interest Income | Interest Income | | 0.2 | | | 0.6 | | | 0.8 | | | 1.4 | | Interest Income | | 2.6 | | | 0.2 | | | 3.0 | | | 0.8 | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 4.3 | | | 6.7 | | | 12.1 | | | 11.5 | | Allowance for Equity Funds Used During Construction | | 2.2 | | | 4.3 | | | 6.8 | | | 12.1 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 4.7 | | | 4.7 | | | 14.2 | | | 14.1 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 7.3 | | | 4.7 | | | 21.8 | | | 14.2 | |
Interest Expense | Interest Expense | | (52.8) | | | (55.0) | | | (160.6) | | | (162.2) | | Interest Expense | | (61.7) | | | (52.8) | | | (171.1) | | | (160.6) | |
| INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 89.9 | | | 108.9 | | | 294.4 | | | 308.0 | | |
INCOME BEFORE INCOME TAX EXPENSE | | INCOME BEFORE INCOME TAX EXPENSE | | 97.7 | | | 89.9 | | | 327.6 | | | 294.4 | |
| Income Tax Expense (Benefit) | | 3.6 | | | (7.7) | | | 19.3 | | | (5.2) | | |
Income Tax Expense | | Income Tax Expense | | 5.0 | | | 3.6 | | | 24.5 | | | 19.3 | |
| NET INCOME | NET INCOME | | $ | 86.3 | | | $ | 116.6 | | | $ | 275.1 | | | $ | 313.2 | | NET INCOME | | $ | 92.7 | | | $ | 86.3 | | | $ | 303.1 | | | $ | 275.1 | |
| The common stock of APCo is wholly-owned by Parent. | The common stock of APCo is wholly-owned by Parent. | The common stock of APCo is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 86.3 | | | $ | 116.6 | | | $ | 275.1 | | | $ | 313.2 | | Net Income | | $ | 92.7 | | | $ | 86.3 | | | $ | 303.1 | | | $ | 275.1 | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | |
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $2.3 and $(1.2) for Nine Months Ended September 30, 2021 and 2020, Respectively | | (0.3) | | | 0.6 | | | 8.5 | | | (4.4) | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.2) and $(0.3) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(0.8) and $(0.8) for the Nine Months Ended September 30, 2021 and 2020, Respectively | | (1.0) | | | (0.9) | | | (3.1) | | | (2.8) | | |
Cash Flow Hedges, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.2) and $2.3 for Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.2) and $2.3 for Nine Months Ended September 30, 2022 and 2021, Respectively | | (0.2) | | | (0.3) | | | (0.6) | | | 8.5 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.9) and $(0.8) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.3) and $(0.2) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.9) and $(0.8) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | (1.1) | | | (1.0) | | | (3.2) | | | (3.1) | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (1.3) | | | (0.3) | | | 5.4 | | | (7.2) | | TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (1.3) | | | (1.3) | | | (3.8) | | | 5.4 | |
| TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | $ | 85.0 | | | $ | 116.3 | | | $ | 280.5 | | | $ | 306.0 | | TOTAL COMPREHENSIVE INCOME | | $ | 91.4 | | | $ | 85.0 | | | $ | 299.3 | | | $ | 280.5 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | | 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 | | |
| Common Stock Dividends | | (50.0) | | | (50.0) | | |
Net Income | | 116.6 | | | 116.6 | | |
Other Comprehensive Loss | | (0.3) | | | (0.3) | | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2020 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,241.5 | | | $ | (2.2) | | | $ | 4,328.4 | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2020 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,248.0 | | | $ | 7.2 | | | $ | 4,344.3 | | |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 | | TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,248.0 | | | $ | 7.2 | | | $ | 4,344.3 | |
| Common Stock Dividends | Common Stock Dividends | | (12.5) | | | (12.5) | | Common Stock Dividends | | (12.5) | | | (12.5) | |
| Net Income | Net Income | | 122.5 | | | 122.5 | | Net Income | | 122.5 | | | 122.5 | |
Other Comprehensive Income | Other Comprehensive Income | | 7.9 | | | 7.9 | | Other Comprehensive Income | | 7.9 | | | 7.9 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 | TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 | | 260.4 | | | 1,828.7 | | | 2,358.0 | | | 15.1 | | | 4,462.2 | | TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2021 | | 260.4 | | | 1,828.7 | | | 2,358.0 | | | 15.1 | | | 4,462.2 | |
| Common Stock Dividends | Common Stock Dividends | | (12.5) | | | (12.5) | | Common Stock Dividends | | | | (12.5) | | | | | (12.5) | |
| Net Income | Net Income | | 66.3 | | | 66.3 | | Net Income | | | | | | 66.3 | | | | | 66.3 | |
Other Comprehensive Loss | Other Comprehensive Loss | | (1.2) | | | (1.2) | | Other Comprehensive Loss | | | | | | | | (1.2) | | | (1.2) | |
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,411.8 | | | $ | 13.9 | | | $ | 4,514.8 | | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | | 260.4 | | | 1,828.7 | | | 2,411.8 | | | 13.9 | | | 4,514.8 | |
| Common Stock Dividends | Common Stock Dividends | | (12.5) | | | (12.5) | | Common Stock Dividends | | (12.5) | | | (12.5) | |
Net Income | Net Income | | 86.3 | | | 86.3 | | Net Income | | 86.3 | | | 86.3 | |
Other Comprehensive Loss | Other Comprehensive Loss | | (1.3) | | | (1.3) | | Other Comprehensive Loss | | (1.3) | | | (1.3) | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,485.6 | | | $ | 12.6 | | | $ | 4,587.3 | | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,485.6 | | | $ | 12.6 | | | $ | 4,587.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY - DECEMBER 31, 2021 | | $ | 260.4 | | | $ | 1,828.7 | | | $ | 2,534.4 | | | $ | 24.4 | | | $ | 4,647.9 | |
| Common Stock Dividends | | Common Stock Dividends | | (18.8) | | | (18.8) | |
| Net Income | | Net Income | | 120.2 | | | 120.2 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | (1.3) | | | (1.3) | |
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022 | | 260.4 | | | 1,828.7 | | | 2,635.8 | | | 23.1 | | | 4,748.0 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 2.8 | | 2.8 | |
Common Stock Dividends | | Common Stock Dividends | | (18.7) | | | (18.7) | |
Net Income | | Net Income | | 90.2 | | | 90.2 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | (1.2) | | | (1.2) | |
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022 | | 260.4 | | | 1,831.5 | | | 2,707.3 | | | 21.9 | | | 4,821.1 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.5 | | 1.5 | |
Net Income | | Net Income | | 92.7 | | | 92.7 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | (1.3) | | | (1.3) | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022 | | $ | 260.4 | | | $ | 1,833.0 | | | $ | 2,800.0 | | | $ | 20.6 | | | $ | 4,914.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 5.0 | | | $ | 5.8 | | Cash and Cash Equivalents | | $ | 6.7 | | | $ | 2.5 | |
Restricted Cash for Securitized Funding | Restricted Cash for Securitized Funding | | 10.1 | | | 16.9 | | Restricted Cash for Securitized Funding | | 7.4 | | | 17.6 | |
Advances to Affiliates | Advances to Affiliates | | 185.2 | | | 21.4 | | Advances to Affiliates | | 182.1 | | | 20.8 | |
Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 119.3 | | | 142.8 | | Customers | | 133.7 | | | 158.5 | |
Affiliated Companies | Affiliated Companies | | 77.4 | | | 64.3 | | Affiliated Companies | | 92.6 | | | 129.9 | |
Accrued Unbilled Revenues | Accrued Unbilled Revenues | | 53.6 | | | 80.1 | | Accrued Unbilled Revenues | | 49.6 | | | 54.0 | |
Miscellaneous | Miscellaneous | | 0.2 | | | 0.3 | | Miscellaneous | | 0.3 | | | 0.2 | |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | | (1.6) | | | (3.1) | | Allowance for Uncollectible Accounts | | (1.5) | | | (1.6) | |
Total Accounts Receivable | Total Accounts Receivable | | 248.9 | | | 284.4 | | Total Accounts Receivable | | 274.7 | | | 341.0 | |
Fuel | Fuel | | 66.6 | | | 193.6 | | Fuel | | 118.6 | | | 67.1 | |
Materials and Supplies | Materials and Supplies | | 100.3 | | | 99.6 | | Materials and Supplies | | 120.4 | | | 109.8 | |
Risk Management Assets | Risk Management Assets | | 47.0 | | | 22.4 | | Risk Management Assets | | 106.8 | | | 42.0 | |
| Accrued Tax Benefits | | Accrued Tax Benefits | | 106.7 | | | 38.1 | |
Regulatory Asset for Under-Recovered Fuel Costs | Regulatory Asset for Under-Recovered Fuel Costs | | 49.2 | | | 5.3 | | Regulatory Asset for Under-Recovered Fuel Costs | | 404.0 | | | 201.3 | |
| Margin Deposits | | Margin Deposits | | 6.1 | | | 71.8 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 72.1 | | | 24.7 | | Prepayments and Other Current Assets | | 17.5 | | | 13.3 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 784.4 | | | 674.1 | | TOTAL CURRENT ASSETS | | 1,351.0 | | | 925.3 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Generation | Generation | | 6,670.8 | | | 6,633.7 | | Generation | | 6,731.0 | | | 6,683.9 | |
Transmission | Transmission | | 4,052.9 | | | 3,900.5 | | Transmission | | 4,445.2 | | | 4,322.4 | |
Distribution | Distribution | | 4,621.1 | | | 4,464.3 | | Distribution | | 4,849.1 | | | 4,683.3 | |
Other Property, Plant and Equipment | Other Property, Plant and Equipment | | 682.4 | | | 627.2 | | Other Property, Plant and Equipment | | 853.3 | | | 696.6 | |
Construction Work in Progress | Construction Work in Progress | | 567.7 | | | 484.6 | | Construction Work in Progress | | 617.7 | | | 469.9 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 16,594.9 | | | 16,110.3 | | Total Property, Plant and Equipment | | 17,496.3 | | | 16,856.1 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 4,973.1 | | | 4,716.2 | | Accumulated Depreciation and Amortization | | 5,332.7 | | | 5,051.8 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 11,621.8 | | | 11,394.1 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 12,163.6 | | | 11,804.3 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 818.6 | | | 686.3 | | Regulatory Assets | | 970.3 | | | 757.6 | |
Securitized Assets | Securitized Assets | | 191.3 | | | 210.1 | | Securitized Assets | | 165.9 | | | 185.1 | |
Employee Benefits and Pension Assets | Employee Benefits and Pension Assets | | 156.8 | | | 150.1 | | Employee Benefits and Pension Assets | | 231.6 | | | 220.5 | |
| Operating Lease Assets | Operating Lease Assets | | 70.4 | | | 78.8 | | Operating Lease Assets | | 61.2 | | | 66.9 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 93.5 | | | 121.7 | | Deferred Charges and Other Noncurrent Assets | | 99.4 | | | 129.2 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 1,330.6 | | | 1,247.0 | | TOTAL OTHER NONCURRENT ASSETS | | 1,528.4 | | | 1,359.3 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 13,736.8 | | | $ | 13,315.2 | | TOTAL ASSETS | | $ | 15,043.0 | | | $ | 14,088.9 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20212022 and December 31, 20202021
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | — | | | $ | 18.6 | | Advances from Affiliates | | $ | — | | | $ | 199.3 | |
Accounts Payable: | Accounts Payable: | | | | | Accounts Payable: | | | | |
General | General | | 224.7 | | | 212.0 | | General | | 374.6 | | | 262.2 | |
Affiliated Companies | Affiliated Companies | | 97.2 | | | 97.1 | | Affiliated Companies | | 168.2 | | | 118.6 | |
Long-term Debt Due Within One Year – Nonaffiliated | Long-term Debt Due Within One Year – Nonaffiliated | | 380.6 | | | 518.3 | | Long-term Debt Due Within One Year – Nonaffiliated | | 351.8 | | | 480.7 | |
| Customer Deposits | Customer Deposits | | 72.9 | | | 77.8 | | Customer Deposits | | 76.8 | | | 73.9 | |
| Accrued Taxes | Accrued Taxes | | 88.5 | | | 109.9 | | Accrued Taxes | | 89.4 | | | 119.7 | |
Accrued Interest | Accrued Interest | | 80.0 | | | 49.9 | | Accrued Interest | | 84.1 | | | 47.9 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 15.1 | | | 14.9 | | Obligations Under Operating Leases | | 14.4 | | | 15.1 | |
| Other Current Liabilities | Other Current Liabilities | | 107.6 | | | 119.2 | | Other Current Liabilities | | 116.8 | | | 98.5 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 1,066.6 | | | 1,217.7 | | TOTAL CURRENT LIABILITIES | | 1,276.1 | | | 1,415.9 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 4,557.2 | | | 4,315.8 | | Long-term Debt – Nonaffiliated | | 5,158.0 | | | 4,458.2 | |
| Deferred Income Taxes | Deferred Income Taxes | | 1,739.3 | | | 1,749.9 | | Deferred Income Taxes | | 1,937.0 | | | 1,804.7 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,250.9 | | | 1,224.7 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,218.4 | | | 1,238.8 | |
Asset Retirement Obligations | Asset Retirement Obligations | | 393.6 | | | 304.8 | | Asset Retirement Obligations | | 418.8 | | | 394.9 | |
Employee Benefits and Pension Obligations | Employee Benefits and Pension Obligations | | 42.9 | | | 44.0 | | Employee Benefits and Pension Obligations | | 40.2 | | | 41.5 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 55.9 | | | 64.4 | | Obligations Under Operating Leases | | 47.3 | | | 52.4 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 43.1 | | | 49.6 | | Deferred Credits and Other Noncurrent Liabilities | | 33.2 | | | 34.6 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 8,082.9 | | | 7,753.2 | | TOTAL NONCURRENT LIABILITIES | | 8,852.9 | | | 8,025.1 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 9,149.5 | | | 8,970.9 | | TOTAL LIABILITIES | | 10,129.0 | | | 9,441.0 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| COMMON SHAREHOLDER’S EQUITY | COMMON SHAREHOLDER’S EQUITY | | | | | COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | Common Stock – No Par Value: | | | | | Common Stock – No Par Value: | | | | |
Authorized – 30,000,000 Shares | Authorized – 30,000,000 Shares | | | | | Authorized – 30,000,000 Shares | | | | |
Outstanding – 13,499,500 Shares | Outstanding – 13,499,500 Shares | | 260.4 | | | 260.4 | | Outstanding – 13,499,500 Shares | | 260.4 | | | 260.4 | |
Paid-in Capital | Paid-in Capital | | 1,828.7 | | | 1,828.7 | | Paid-in Capital | | 1,833.0 | | | 1,828.7 | |
Retained Earnings | Retained Earnings | | 2,485.6 | | | 2,248.0 | | Retained Earnings | | 2,800.0 | | | 2,534.4 | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | 12.6 | | | 7.2 | | Accumulated Other Comprehensive Income (Loss) | | 20.6 | | | 24.4 | |
TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 4,587.3 | | | 4,344.3 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 4,914.0 | | | 4,647.9 | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 13,736.8 | | | $ | 13,315.2 | | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 15,043.0 | | | $ | 14,088.9 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 275.1 | | | $ | 313.2 | | Net Income | | $ | 303.1 | | | $ | 275.1 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | Depreciation and Amortization | | 406.6 | | | 366.0 | | Depreciation and Amortization | | 431.0 | | | 406.6 | |
Deferred Income Taxes | Deferred Income Taxes | | (12.0) | | | (28.2) | | Deferred Income Taxes | | 70.7 | | | (12.0) | |
| Asset Impairments and Other Related Charges - Coal Fired Generation | | Asset Impairments and Other Related Charges - Coal Fired Generation | | 24.9 | | | — | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (12.1) | | | (11.5) | | Allowance for Equity Funds Used During Construction | | (6.8) | | | (12.1) | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | (26.8) | | | 8.0 | | Mark-to-Market of Risk Management Contracts | | (65.6) | | | (26.8) | |
Pension Contributions to Qualified Plan Trust | | — | | | (7.0) | | |
| | Deferred Fuel Over/Under-Recovery, Net | Deferred Fuel Over/Under-Recovery, Net | | (43.9) | | | 38.8 | | Deferred Fuel Over/Under-Recovery, Net | | (400.2) | | | (43.9) | |
Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | Establishment of 2017-2019 Virginia Triennial Review Regulatory Asset | | (37.0) | | | — | |
Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | (39.2) | | | 5.4 | | Change in Other Noncurrent Assets | | (15.2) | | | (39.2) | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 20.2 | | | (26.0) | | Change in Other Noncurrent Liabilities | | 39.7 | | | 20.2 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | 38.1 | | | 7.2 | | Accounts Receivable, Net | | 68.7 | | | 38.1 | |
Fuel, Materials and Supplies | Fuel, Materials and Supplies | | 126.3 | | | 12.4 | | Fuel, Materials and Supplies | | (61.7) | | | 126.3 | |
Margin Deposits | | Margin Deposits | | 65.8 | | | (15.8) | |
Accounts Payable | Accounts Payable | | 26.5 | | | (74.0) | | Accounts Payable | | 141.4 | | | 26.5 | |
Accrued Taxes, Net | Accrued Taxes, Net | | (48.0) | | | 1.9 | | Accrued Taxes, Net | | (98.9) | | | (48.0) | |
Other Current Assets | Other Current Assets | | (20.7) | | | 10.1 | | Other Current Assets | | (4.2) | | | (4.9) | |
Other Current Liabilities | Other Current Liabilities | | 0.5 | | | (9.7) | | Other Current Liabilities | | 42.2 | | | 0.5 | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | | 690.6 | | | 606.6 | | Net Cash Flows from Operating Activities | | 497.9 | | | 690.6 | |
| INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (586.4) | | | (566.6) | | Construction Expenditures | | (707.4) | | | (586.4) | |
| Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | (163.8) | | | (137.4) | | Change in Advances to Affiliates, Net | | (161.3) | | | (163.8) | |
| Other Investing Activities | Other Investing Activities | | 12.4 | | | 4.6 | | Other Investing Activities | | 34.9 | | | 12.4 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (737.8) | | | (699.4) | | Net Cash Flows Used for Investing Activities | | (833.8) | | | (737.8) | |
| FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Capital Contribution from Parent | | Capital Contribution from Parent | | 4.3 | | | — | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 494.0 | | | 557.2 | | Issuance of Long-term Debt – Nonaffiliated | | 698.2 | | | 494.0 | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (18.6) | | | (232.4) | | Change in Advances from Affiliates, Net | | (199.3) | | | (18.6) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (393.0) | | | (90.3) | | Retirement of Long-term Debt – Nonaffiliated | | (130.4) | | | (393.0) | |
| Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (5.8) | | | (5.6) | | Principal Payments for Finance Lease Obligations | | (5.9) | | | (5.8) | |
Dividends Paid on Common Stock | Dividends Paid on Common Stock | | (37.5) | | | (150.0) | | Dividends Paid on Common Stock | | (37.5) | | | (37.5) | |
Other Financing Activities | Other Financing Activities | | 0.5 | | | 0.3 | | Other Financing Activities | | 0.5 | | | 0.5 | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 39.6 | | | 79.2 | | Net Cash Flows from Financing Activities | | 329.9 | | | 39.6 | |
| Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (7.6) | | | (13.6) | | Net Decrease in Cash, Cash Equivalents and Restricted Cash for Securitized Funding | | (6.0) | | | (7.6) | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at Beginning of Period | 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 Beginning of Period | | 20.1 | | | 22.7 | |
Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 15.1 | | | $ | 13.2 | | Cash, Cash Equivalents and Restricted Cash for Securitized Funding at End of Period | | $ | 14.1 | | | $ | 15.1 | |
| SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 124.2 | | | $ | 130.0 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 128.3 | | | $ | 124.2 | |
Net Cash Paid (Received) for Income Taxes | | 52.6 | | | (10.7) | | |
Net Cash Paid for Income Taxes | | Net Cash Paid for Income Taxes | | 14.2 | | | 52.6 | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 1.3 | | | 3.0 | | Noncash Acquisitions Under Finance Leases | | 1.0 | | | 1.3 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 92.3 | | | 90.0 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 160.4 | | | 92.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | Retail: | | | | | | | |
Residential | Residential | 1,531 | | | 1,531 | | | 4,244 | | | 4,230 | | Residential | 1,532 | | | 1,531 | | | 4,320 | | | 4,244 | |
Commercial | Commercial | 1,267 | | | 1,219 | | | 3,481 | | | 3,362 | | Commercial | 1,326 | | | 1,267 | | | 3,610 | | | 3,481 | |
Industrial | Industrial | 1,853 | | | 1,849 | | | 5,542 | | | 5,324 | | Industrial | 1,926 | | | 1,853 | | | 5,638 | | | 5,542 | |
Miscellaneous | Miscellaneous | 13 | | | 14 | | | 42 | | | 47 | | Miscellaneous | 12 | | | 13 | | | 39 | | | 42 | |
Total Retail | Total Retail | 4,664 | | | 4,613 | | | 13,309 | | | 12,963 | | Total Retail | 4,796 | | | 4,664 | | | 13,607 | | | 13,309 | |
| Wholesale | Wholesale | 1,610 | | | 1,536 | | | 5,055 | | | 5,552 | | Wholesale | 1,707 | | | 1,610 | | | 4,892 | | | 5,055 | |
| Total KWhs | Total KWhs | 6,274 | | | 6,149 | | | 18,364 | | | 18,515 | | Total KWhs | 6,503 | | | 6,274 | | | 18,499 | | | 18,364 | |
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | 2 | | | 7 | | | 2,343 | | | 2,186 | | Actual – Heating (a) | 17 | | | 2 | | | 2,525 | | | 2,343 | |
Normal – Heating (b) | Normal – Heating (b) | 9 | | | 10 | | | 2,417 | | | 2,429 | | Normal – Heating (b) | 8 | | | 9 | | | 2,421 | | | 2,417 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 679 | | | 637 | | | 1,004 | | | 923 | | Actual – Cooling (c) | 590 | | | 679 | | | 934 | | | 1,004 | |
Normal – Cooling (b) | Normal – Cooling (b) | 581 | | | 576 | | | 848 | | | 841 | | Normal – Cooling (b) | 580 | | | 581 | | | 842 | | | 848 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Indiana Michigan Power Company and Subsidiaries |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 76.7104.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 30.910.1 | |
| | |
Margins from Off-system Sales | | 0.2 | |
Transmission Revenues | | (0.2)1.2 | |
Other Revenues | | 4.01.6 | |
Total Change in Gross Margin | | 34.913.1 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (3.0)1.2 | |
| | |
Depreciation and Amortization | | (6.1)(21.0) | |
Taxes Other Than Income Taxes | | (0.4)5.4 | |
Other Income | | 0.3 (0.1) | |
| | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 2.2 | |
Interest Expense | | (3.3)(1.0) | |
Total Change in Expenses and Other | | (12.5)(13.3) | |
| | |
Income Tax Expense | | 5.0 (9.8) | |
| | |
Third Quarter of 20212022 | | $ | 104.194.1 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:
•Retail Margins increased $31$10 million primarily due to the following:
•A $40$15 million increase primarily due to an increase in rider revenues and the reversal of a provision for refund.revenues. This increase was partially offset in other expense items below.
This increase was partially offset by:
•A $4$7 million increasedecrease in weather-related usage primarily due to a 7 % increase13% decrease in cooling degree days.
•A $2 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $19 million decrease in weather-normalized retail margins primarily in the residential class.
•Other Revenues increased $4 million primarily due to increases in barging revenues by River Transportation Division (RTD), reconnection fees and joint license agreements. The increase in RTD barging revenues are partially offset in Other Operation and Maintenance expenses below.
Expenses and Other and Income TaxesTax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $3decreased $1 million primarily due to the following:
•A $17 million decrease in steam generation expenses primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021. This decrease was partially offset in Depreciation and Amortization expenses below.
This decrease was partially offset by:
•A $10 million increase in transmission expenses primarily due to an increase in recoverable PJM transmission expenses. This increase was partially offset in Retail Margins above.
•��A $5$6 million increase in distributionnuclear expenses at Cook Plant primarily due to an increase in vegetation managementrefueling outage expenses.
•A $2 million increase in nonutility operation expenses primarily due to an increase in RTD expenses. This increase was partially offset in Other Revenues above.
These increases were partially offset by:
•A $9 million decrease in employee-related expenses.
•A $7 million decrease in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.
•Depreciation and Amortization expenses increased $6$21 million primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021 and a higher depreciable base. The increase resulting from the lease modification was partially offset in Other Operation and Maintenance expenses above.
•Taxes Other Than Income Taxes decreased $5 million primarily due to the repeal of the Indiana Utility Receipts Tax in July 2022. This increasedecrease was partially offset in Retail Margins above.
•Income Tax Expense decreased $5increased $10 million primarily due to an increasea decrease in amortization of Excess ADIT, a decrease in the benefit from investment tax credit amortization, and flow through tax benefits and an unfavorable discrete tax adjustment recordeda decrease in 2020 that did not recur in 2021, partially offset by an increase to pretax book income. The increase in amortization of Excess ADIT is partially offset above in Retail Margins.parent company loss benefit.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Indiana Michigan Power Company and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 232.8232.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 57.052.4 | |
| | |
Margins from Off-system Sales | | 0.4 | |
Transmission Revenues | | (5.2)11.3 | |
Other Revenues | | 4.06.2 | |
Total Change in Gross Margin | | 55.870.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (43.7)29.2 | |
| | |
Depreciation and Amortization | | (25.1)(71.5) | |
Taxes Other Than Income Taxes | | (4.3)7.6 | |
Other Income | | 1.1 (1.5) | |
| | |
| | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.2)6.5 | |
Interest Expense | | (0.9)(5.9) | |
Total Change in Expenses and Other | | (73.1)(35.6) | |
| | |
Income Tax Expense | | 16.6 (16.0) | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 232.1250.8 | |
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 Margins increased $57$52 million primarily due to the following:
•An $88A $43 million increase due to the annualincreased rider revenues partially offset by lower wholesale formula rate true-up, an increase in Indiana and Michigan base rate revenues and an increase in rider revenues.true-ups. This increase was partially offset in other expense items below.
•A $14$6 million increase in weather-related usage primarily due to a 7% increase in heating degree days and a 9% increase in cooling degree days.
•A $5 million decrease in fuel related expenses due to timing of recovery related to wholesale contracts.
These increases were partially offset by:
•A $36 million decrease in weather-normalized retail margins primarily in the residentialcommercial class.
•A $24 million decrease in weather-normalized wholesale margins, including the loss of a significant wholesale contract.
•Transmission Revenues decreased $5increased $11 million primarily due to the annualfollowing:
•A $7 million increase due to transmission formula rate true-up.true-up activity.
•A $4 million increase due to continued investment in transmission assets.
•Other Revenues increased $4$6 million primarily due to an increasea gain on sale of allowances and economic hedging activities. The gain on sale of allowances was partially offset in reconnection fees and joint license agreements.Retail Margins above.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $44decreased $29 million primarily due to the following:
•A $27$54 million increasedecrease in recoverable PJM transmission expenses.steam generation expenses primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021. This increasedecrease was partially offset in Retail Margins above.Depreciation and Amortization expenses below.
•A $17$4 million decrease due to an increased Nuclear Electric Insurance Limited distribution in 2022.
These decreases were partially offset by:
•A $14 million increase in nuclear expenses at Cook Plant primarily due to refueling outage expenses.
•A $13 million increase in transmission expenses primarily due to an $8the following:
•A $31 million increase in vegetation managementrecoverable PJM expenses. These expenses and a $6 millionwere offset in Retail Margins above.
This increase as a result of the annual transmission formula rate true-up.
•An $8A $9 million increasedecrease in distribution expenses primarily due to an increase intransmission 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 $17$7 million decrease in Indiana jurisdictional Demand Side Management expenses. This decrease was offset in Retail Margins above.
•A $4 million decrease in nuclear expenses primarily due to a $9 million decrease in Cook Plant refueling outage expenses partially offset by a $5 million increase in various maintenance activities.transmission formula rate true-up activity.
•Depreciation and Amortization expenses increased $25$72 million primarily due to the modification of the Rockport Plant, Unit 2 lease, which resulted in a change in lease classification from an operating lease to a finance lease in December 2021, and a higher depreciable basebase. The increase resulting from the lease modification was partially offset in Other Operation and an increaseMaintenance expenses above.
•Taxes Other Than Income Taxes decreased $8 million primarily due to the repeal of the Indiana Utility Receipts Tax in depreciation rates.July 2022. This increasedecrease was partially offset in Retail Margins above.
•Taxes Other Than Income TaxesNon-Service Cost Components of Net Periodic Benefit Cost increased $4decreased $7 million primarily due to property taxes driven by an increase in utility plantdiscount rates, an increase in the expected return on plan assets and higher tax rates.favorable plan returns in 2021.
•Interest Expense increased $6 million primarily due to a debt issuance in April 2021.
•Income Tax Expense decreased $17increased $16 million primarily due to an increase in flow through tax benefits,pretax book income, a decrease in state incomethe benefit from investment tax expensecredit amortization, and a decrease in pretax book income.parent company loss benefit.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | Electric Generation, Transmission and Distribution | | $ | 618.2 | | | $ | 570.1 | | | $ | 1,735.1 | | | $ | 1,648.4 | | Electric Generation, Transmission and Distribution | | $ | 695.7 | | | $ | 618.2 | | | $ | 1,912.1 | | | $ | 1,735.1 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 1.1 | | | 1.3 | | | 2.6 | | | 9.1 | | Sales to AEP Affiliates | | 2.0 | | | 1.1 | | | 11.1 | | | 2.6 | |
Other Revenues – Affiliated | Other Revenues – Affiliated | | 14.7 | | | 14.1 | | | 41.2 | | | 42.4 | | Other Revenues – Affiliated | | 13.3 | | | 14.7 | | | 38.4 | | | 41.2 | |
Other Revenues – Nonaffiliated | Other Revenues – Nonaffiliated | | 1.7 | | | 1.2 | | | 5.1 | | | 3.7 | | Other Revenues – Nonaffiliated | | 4.4 | | | 1.7 | | | 10.0 | | | 5.1 | |
TOTAL REVENUES | TOTAL REVENUES | | 635.7 | | | 586.7 | | | 1,784.0 | | | 1,703.6 | | TOTAL REVENUES | | 715.4 | | | 635.7 | | | 1,971.6 | | | 1,784.0 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | 43.7 | | | 44.4 | | | 129.9 | | | 146.0 | | |
Purchased Electricity for Resale | | 44.9 | | | 37.5 | | | 131.9 | | | 128.1 | | |
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 150.6 | | | 88.6 | | | 367.2 | | | 261.8 | |
| Purchased Electricity from AEP Affiliates | Purchased Electricity from AEP Affiliates | | 63.3 | | | 55.9 | | | 172.7 | | | 135.8 | | Purchased Electricity from AEP Affiliates | | 67.9 | | | 63.3 | | | 184.6 | | | 172.7 | |
Other Operation | Other Operation | | 167.5 | | | 165.5 | | | 482.4 | | | 459.7 | | Other Operation | | 162.4 | | | 167.5 | | | 450.9 | | | 482.4 | |
Maintenance | Maintenance | | 52.0 | | | 51.0 | | | 165.4 | | | 144.4 | | Maintenance | | 55.9 | | | 52.0 | | | 167.7 | | | 165.4 | |
| Depreciation and Amortization | Depreciation and Amortization | | 110.6 | | | 104.5 | | | 328.7 | | | 303.6 | | Depreciation and Amortization | | 131.6 | | | 110.6 | | | 400.2 | | | 328.7 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 27.8 | | | 27.4 | | | 83.8 | | | 79.5 | | Taxes Other Than Income Taxes | | 22.4 | | | 27.8 | | | 76.2 | | | 83.8 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 509.8 | | | 486.2 | | | 1,494.8 | | | 1,397.1 | | TOTAL EXPENSES | | 590.8 | | | 509.8 | | | 1,646.8 | | | 1,494.8 | |
| OPERATING INCOME | OPERATING INCOME | | 125.9 | | | 100.5 | | | 289.2 | | | 306.5 | | OPERATING INCOME | | 124.6 | | | 125.9 | | | 324.8 | | | 289.2 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Other Income | Other Income | | 2.5 | | | 2.2 | | | 8.9 | | | 7.8 | | Other Income | | 2.4 | | | 2.5 | | | 7.4 | | | 8.9 | |
| Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 4.1 | | | 4.1 | | | 12.3 | | | 12.5 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 6.3 | | | 4.1 | | | 18.8 | | | 12.3 | |
Interest Expense | Interest Expense | | (30.2) | | | (26.9) | | | (86.6) | | | (85.7) | | Interest Expense | | (31.2) | | | (30.2) | | | (92.5) | | | (86.6) | |
| INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 102.3 | | | 79.9 | | | 223.8 | | | 241.1 | | INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 102.1 | | | 102.3 | | | 258.5 | | | 223.8 | |
| Income Tax Expense (Benefit) | Income Tax Expense (Benefit) | | (1.8) | | | 3.2 | | | (8.3) | | | 8.3 | | Income Tax Expense (Benefit) | | 8.0 | | | (1.8) | | | 7.7 | | | (8.3) | |
| NET INCOME | NET INCOME | | $ | 104.1 | | | $ | 76.7 | | | $ | 232.1 | | | $ | 232.8 | | NET INCOME | | $ | 94.1 | | | $ | 104.1 | | | $ | 250.8 | | | $ | 232.1 | |
| The common stock of I&M is wholly-owned by Parent. | The common stock of I&M is wholly-owned by Parent. | The common stock of I&M is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 104.1 | | | $ | 76.7 | | | $ | 232.1 | | | $ | 232.8 | | Net Income | | $ | 94.1 | | | $ | 104.1 | | | $ | 250.8 | | | $ | 232.1 | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | 0.4 | | | 0.4 | | | 1.3 | | | 1.2 | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | — | | | (0.1) | | | (0.1) | | | (0.1) | | |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | 0.4 | | | 0.4 | | | 1.2 | | | 1.3 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.1) and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.1) and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | (0.1) | | | — | | | (0.3) | | | (0.1) | |
| TOTAL OTHER COMPREHENSIVE INCOME | TOTAL OTHER COMPREHENSIVE INCOME | | 0.4 | | | 0.3 | | | 1.2 | | | 1.1 | | TOTAL OTHER COMPREHENSIVE INCOME | | 0.3 | | | 0.4 | | | 0.9 | | | 1.2 | |
| TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | $ | 104.5 | | | $ | 77.0 | | | $ | 233.3 | | | $ | 233.9 | | TOTAL COMPREHENSIVE INCOME | | $ | 94.4 | | | $ | 104.5 | | | $ | 251.7 | | | $ | 233.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(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 | | |
| Common Stock Dividends | | (21.2) | | | (21.2) | | |
Net Income | | 76.7 | | | 76.7 | | |
Other Comprehensive Income | | 0.3 | | | 0.3 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2020 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,688.0 | | | $ | (10.5) | | | $ | 2,715.0 | | |
| | | | | | | | | | | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 | TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,718.7 | | | $ | (7.0) | | | $ | 2,749.2 | | TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2020 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,718.7 | | | $ | (7.0) | | | $ | 2,749.2 | |
| Common Stock Dividends | Common Stock Dividends | | (25.0) | | | (25.0) | | Common Stock Dividends | | | | | | (25.0) | | | | | (25.0) | |
| Net Income | Net Income | | 70.8 | | | 70.8 | | Net Income | | | | | | 70.8 | | | | | 70.8 | |
Other Comprehensive Income | Other Comprehensive Income | | 0.5 | | | 0.5 | | 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 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY -MARCH 31, 2021 | | 56.6 | | | 980.9 | | | 1,764.5 | | | (6.5) | | | 2,795.5 | |
| Common Stock Dividends | Common Stock Dividends | | | | | | (75.0) | | | | | (75.0) | | Common Stock Dividends | | (75.0) | | | (75.0) | |
Net Income | Net Income | | | | | | 57.2 | | | | | 57.2 | | Net Income | | 57.2 | | | 57.2 | |
Other Comprehensive Income | Other Comprehensive Income | | | | | | | | 0.3 | | | 0.3 | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | | 56.6 | | | 980.9 | | | 1,746.7 | | | (6.2) | | | 2,778.0 | | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2021 | | 56.6 | | | 980.9 | | | 1,746.7 | | | (6.2) | | | 2,778.0 | |
| Common Stock Dividends | Common Stock Dividends | | (75.0) | | | (75.0) | | Common Stock Dividends | | (75.0) | | | (75.0) | |
Net Income | Net Income | | 104.1 | | | 104.1 | | Net Income | | 104.1 | | | 104.1 | |
Other Comprehensive Income | Other Comprehensive Income | | 0.4 | | | 0.4 | | Other Comprehensive Income | | 0.4 | | | 0.4 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,775.8 | | | $ | (5.8) | | | $ | 2,807.5 | | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2021 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,775.8 | | | $ | (5.8) | | | $ | 2,807.5 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 | | TOTAL COMMON SHAREHOLDER’S EQUITY - DECEMBER 31, 2021 | | $ | 56.6 | | | $ | 980.9 | | | $ | 1,748.5 | | | $ | (1.3) | | | $ | 2,784.7 | |
| Common Stock Dividends | | Common Stock Dividends | | (25.0) | | | (25.0) | |
| Net Income | | Net Income | | 89.5 | | | 89.5 | |
Other Comprehensive Income | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - MARCH 31, 2022 | | 56.6 | | | 980.9 | | | 1,813.0 | | | (1.0) | | | 2,849.5 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.3 | | | 1.3 | |
Common Stock Dividends | | Common Stock Dividends | | | | | | (25.0) | | | | | (25.0) | |
Net Income | | Net Income | | | | | | 67.2 | | | | | 67.2 | |
Other Comprehensive Income | | Other Comprehensive Income | | | | | | | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - JUNE 30, 2022 | | 56.6 | | | 982.2 | | | 1,855.2 | | | (0.7) | | | 2,893.3 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 0.6 | | 0.6 | |
Common Stock Dividends | | Common Stock Dividends | | (20.0) | | | (20.0) | |
Net Income | | Net Income | | 94.1 | | | 94.1 | |
Other Comprehensive Income | | Other Comprehensive Income | | 0.3 | | | 0.3 | |
TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY - SEPTEMBER 30, 2022 | | $ | 56.6 | | | $ | 982.8 | | | $ | 1,929.3 | | | $ | (0.4) | | | $ | 2,968.3 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | September 30, | | December 31, | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 3.2 | | | $ | 3.3 | | Cash and Cash Equivalents | | $ | 25.8 | | | $ | 1.3 | |
Advances to Affiliates | Advances to Affiliates | | 80.6 | | | 13.3 | | Advances to Affiliates | | 22.6 | | | 21.5 | |
Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 39.8 | | | 44.0 | | Customers | | 40.8 | | | 40.6 | |
Affiliated Companies | Affiliated Companies | | 37.9 | | | 51.3 | | Affiliated Companies | | 72.7 | | | 78.2 | |
| Accrued Unbilled Revenues | | Accrued Unbilled Revenues | | 0.4 | | | — | |
Miscellaneous | Miscellaneous | | 2.8 | | | 2.0 | | Miscellaneous | | 3.4 | | | 2.5 | |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | | (0.3) | | | (0.3) | | Allowance for Uncollectible Accounts | | — | | | (0.1) | |
Total Accounts Receivable | Total Accounts Receivable | | 80.2 | | | 97.0 | | Total Accounts Receivable | | 117.3 | | | 121.2 | |
Fuel | Fuel | | 46.7 | | | 86.0 | | Fuel | | 49.5 | | | 56.8 | |
Materials and Supplies | Materials and Supplies | | 172.2 | | | 175.8 | | Materials and Supplies | | 179.4 | | | 175.2 | |
Risk Management Assets | | 5.5 | | | 3.6 | | |
Accrued Tax Benefits | | 0.1 | | | 10.3 | | |
| Regulatory Asset for Under-Recovered Fuel Costs | Regulatory Asset for Under-Recovered Fuel Costs | | 6.1 | | | 5.4 | | Regulatory Asset for Under-Recovered Fuel Costs | | 25.4 | | | 6.4 | |
| Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 26.7 | | | 24.1 | | Prepayments and Other Current Assets | | 50.0 | | | 57.0 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 421.3 | | | 418.8 | | TOTAL CURRENT ASSETS | | 470.0 | | | 439.4 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Generation | Generation | | 5,329.6 | | | 5,264.7 | | Generation | | 5,601.6 | | | 5,531.8 | |
Transmission | Transmission | | 1,749.4 | | | 1,696.4 | | Transmission | | 1,823.9 | | | 1,783.1 | |
Distribution | Distribution | | 2,734.6 | | | 2,594.6 | | Distribution | | 2,955.9 | | | 2,800.1 | |
Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 684.5 | | | 686.7 | | Other Property, Plant and Equipment (Including Coal Mining and Nuclear Fuel) | | 854.6 | | | 792.9 | |
Construction Work in Progress | Construction Work in Progress | | 377.6 | | | 362.4 | | Construction Work in Progress | | 314.7 | | | 302.8 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 10,875.7 | | | 10,604.8 | | Total Property, Plant and Equipment | | 11,550.7 | | | 11,210.7 | |
Accumulated Depreciation, Depletion and Amortization | Accumulated Depreciation, Depletion and Amortization | | 3,811.9 | | | 3,552.5 | | Accumulated Depreciation, Depletion and Amortization | | 4,161.3 | | | 3,899.8 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,063.8 | | | 7,052.3 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,389.4 | | | 7,310.9 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 436.1 | | | 404.8 | | Regulatory Assets | | 422.5 | | | 410.9 | |
Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | 3,609.8 | | | 3,306.7 | | Spent Nuclear Fuel and Decommissioning Trusts | | 3,130.5 | | | 3,867.0 | |
| Operating Lease Assets | Operating Lease Assets | | 154.7 | | | 218.1 | | Operating Lease Assets | | 51.9 | | | 63.5 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 219.5 | | | 237.6 | | Deferred Charges and Other Noncurrent Assets | | 278.5 | | | 316.5 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 4,420.1 | | | 4,167.2 | | TOTAL OTHER NONCURRENT ASSETS | | 3,883.4 | | | 4,657.9 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 11,905.2 | | | $ | 11,638.3 | | TOTAL ASSETS | | $ | 11,742.8 | | | $ | 12,408.2 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20212022 and December 31, 20202021
(dollars in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | — | | | $ | 103.0 | | Advances from Affiliates | | $ | 104.9 | | | $ | 93.3 | |
Accounts Payable: | Accounts Payable: | | | | | Accounts Payable: | | | | |
General | General | | 132.8 | | | 153.2 | | General | | 187.3 | | | 174.4 | |
Affiliated Companies | Affiliated Companies | | 86.2 | | | 80.5 | | Affiliated Companies | | 94.0 | | | 94.9 | |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2021 and December 31, 2020 Amounts Include $78.7 and $75.7, Respectively, Related to DCC Fuel) | | 132.7 | | | 369.6 | | |
Risk Management Liabilities | | 2.5 | | | 0.1 | | |
Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $68.8 and $65, Respectively, Related to DCC Fuel) | | Long-term Debt Due Within One Year – Nonaffiliated (September 30, 2022 and December 31, 2021 Amounts Include $68.8 and $65, Respectively, Related to DCC Fuel) | | 320.9 | | | 67.0 | |
| Customer Deposits | Customer Deposits | | 42.4 | | | 41.7 | | Customer Deposits | | 43.0 | | | 45.2 | |
Accrued Taxes | Accrued Taxes | | 72.0 | | | 102.5 | | Accrued Taxes | | 76.9 | | | 106.5 | |
Accrued Interest | Accrued Interest | | 25.0 | | | 35.6 | | Accrued Interest | | 24.5 | | | 37.0 | |
Obligations Under Finance Leases | | Obligations Under Finance Leases | | 94.1 | | | 130.5 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 86.2 | | | 85.6 | | Obligations Under Operating Leases | | 11.3 | | | 15.5 | |
Regulatory Liability for Over-Recovered Fuel Costs | Regulatory Liability for Over-Recovered Fuel Costs | | 3.5 | | | 20.8 | | Regulatory Liability for Over-Recovered Fuel Costs | | — | | | 1.5 | |
Other Current Liabilities | Other Current Liabilities | | 104.2 | | | 111.9 | | Other Current Liabilities | | 92.5 | | | 128.2 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 687.5 | | | 1,104.5 | | TOTAL CURRENT LIABILITIES | | 1,049.4 | | | 894.0 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 3,098.4 | | | 2,660.3 | | Long-term Debt – Nonaffiliated | | 2,885.8 | | | 3,128.0 | |
| Deferred Income Taxes | Deferred Income Taxes | | 1,082.9 | | | 1,064.4 | | Deferred Income Taxes | | 1,143.6 | | | 1,100.2 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 2,201.2 | | | 2,041.9 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,577.0 | | | 2,447.9 | |
Asset Retirement Obligations | Asset Retirement Obligations | | 1,869.2 | | | 1,812.9 | | Asset Retirement Obligations | | 2,009.8 | | | 1,946.2 | |
Obligations Under Operating Leases | Obligations Under Operating Leases | | 88.4 | | | 135.9 | | Obligations Under Operating Leases | | 41.6 | | | 48.9 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 70.1 | | | 69.2 | | Deferred Credits and Other Noncurrent Liabilities | | 67.3 | | | 58.3 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 8,410.2 | | | 7,784.6 | | TOTAL NONCURRENT LIABILITIES | | 7,725.1 | | | 8,729.5 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 9,097.7 | | | 8,889.1 | | TOTAL LIABILITIES | | 8,774.5 | | | 9,623.5 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| COMMON SHAREHOLDER’S EQUITY | COMMON SHAREHOLDER’S EQUITY | | | | | COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – No Par Value: | Common Stock – No Par Value: | | | | | Common Stock – No Par Value: | | | | |
Authorized – 2,500,000 Shares | Authorized – 2,500,000 Shares | | | | | Authorized – 2,500,000 Shares | | | | |
Outstanding – 1,400,000 Shares | Outstanding – 1,400,000 Shares | | 56.6 | | | 56.6 | | Outstanding – 1,400,000 Shares | | 56.6 | | | 56.6 | |
Paid-in Capital | Paid-in Capital | | 980.9 | | | 980.9 | | Paid-in Capital | | 982.8 | | | 980.9 | |
Retained Earnings | Retained Earnings | | 1,775.8 | | | 1,718.7 | | Retained Earnings | | 1,929.3 | | | 1,748.5 | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | (5.8) | | | (7.0) | | Accumulated Other Comprehensive Income (Loss) | | (0.4) | | | (1.3) | |
TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,807.5 | | | 2,749.2 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,968.3 | | | 2,784.7 | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 11,905.2 | | | $ | 11,638.3 | | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 11,742.8 | | | $ | 12,408.2 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 232.1 | | | $ | 232.8 | | Net Income | | $ | 250.8 | | | $ | 232.1 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | |
Depreciation and Amortization | Depreciation and Amortization | | 328.7 | | | 303.6 | | Depreciation and Amortization | | 400.2 | | | 328.7 | |
Rockport Plant, Unit 2 Operating Lease Amortization | Rockport Plant, Unit 2 Operating Lease Amortization | | 51.1 | | | 51.9 | | Rockport Plant, Unit 2 Operating Lease Amortization | | — | | | 51.1 | |
Deferred Income Taxes | Deferred Income Taxes | | (36.6) | | | (6.1) | | Deferred Income Taxes | | (15.8) | | | (36.6) | |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | (2.5) | | | 21.3 | | |
Deferral of Incremental Nuclear Refueling Outage Expenses, Net | | Deferral of Incremental Nuclear Refueling Outage Expenses, Net | | (35.2) | | | (2.5) | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (9.7) | | | (8.8) | | Allowance for Equity Funds Used During Construction | | (7.9) | | | (9.7) | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | 0.5 | | | 5.6 | | Mark-to-Market of Risk Management Contracts | | (13.2) | | | 0.5 | |
Amortization of Nuclear Fuel | Amortization of Nuclear Fuel | | 61.9 | | | 67.2 | | Amortization of Nuclear Fuel | | 63.1 | | | 61.9 | |
Pension Contributions to Qualified Plan Trust | | — | | | (6.4) | | |
| Deferred Fuel Over/Under-Recovery, Net | Deferred Fuel Over/Under-Recovery, Net | | (18.0) | | | 23.4 | | Deferred Fuel Over/Under-Recovery, Net | | (20.5) | | | (18.0) | |
Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | 7.3 | | | 40.8 | | Change in Other Noncurrent Assets | | 12.5 | | | 7.3 | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | (10.2) | | | 30.2 | | Change in Other Noncurrent Liabilities | | 42.1 | | | (10.2) | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | 18.2 | | | 32.2 | | Accounts Receivable, Net | | 5.3 | | | 18.2 | |
Fuel, Materials and Supplies | Fuel, Materials and Supplies | | 43.0 | | | (15.4) | | Fuel, Materials and Supplies | | 3.1 | | | 43.0 | |
| Accounts Payable | Accounts Payable | | 20.1 | | | (0.9) | | Accounts Payable | | 19.6 | | | 20.1 | |
| Accrued Taxes, Net | Accrued Taxes, Net | | (20.3) | | | (84.4) | | Accrued Taxes, Net | | (17.0) | | | (20.3) | |
| Rockport Plant, Unit 2 Operating Lease Payments | Rockport Plant, Unit 2 Operating Lease Payments | | (36.9) | | | (36.9) | | Rockport Plant, Unit 2 Operating Lease Payments | | — | | | (36.9) | |
Other Current Assets | Other Current Assets | | (0.7) | | | 6.6 | | Other Current Assets | | 19.3 | | | (0.7) | |
Other Current Liabilities | Other Current Liabilities | | (28.0) | | | (59.1) | | Other Current Liabilities | | (63.6) | | | (28.0) | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | | 600.0 | | | 597.6 | | Net Cash Flows from Operating Activities | | 642.8 | | | 600.0 | |
| INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (370.2) | | | (409.1) | | Construction Expenditures | | (407.4) | | | (370.2) | |
Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | (67.3) | | | (0.1) | | Change in Advances to Affiliates, Net | | (1.1) | | | (67.3) | |
Purchases of Investment Securities | Purchases of Investment Securities | | (1,586.3) | | | (1,290.0) | | Purchases of Investment Securities | | (1,854.8) | | | (1,586.3) | |
Sales of Investment Securities | Sales of Investment Securities | | 1,556.6 | | | 1,257.1 | | Sales of Investment Securities | | 1,818.4 | | | 1,556.6 | |
Acquisitions of Nuclear Fuel | Acquisitions of Nuclear Fuel | | (63.2) | | | (68.4) | | Acquisitions of Nuclear Fuel | | (91.9) | | | (63.2) | |
| Other Investing Activities | Other Investing Activities | | 12.9 | | | 8.3 | | Other Investing Activities | | 8.0 | | | 12.9 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (517.5) | | | (502.2) | | Net Cash Flows Used for Investing Activities | | (528.8) | | | (517.5) | |
| FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.9 | | | — | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 507.0 | | | — | | Issuance of Long-term Debt – Nonaffiliated | | 72.8 | | | 507.0 | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (103.0) | | | 44.7 | | Change in Advances from Affiliates, Net | | 11.6 | | | (103.0) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (307.2) | | | (71.1) | | Retirement of Long-term Debt – Nonaffiliated | | (64.5) | | | (307.2) | |
Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (4.9) | | | (4.8) | | Principal Payments for Finance Lease Obligations | | (41.6) | | | (4.9) | |
Dividends Paid on Common Stock | Dividends Paid on Common Stock | | (175.0) | | | (63.7) | | Dividends Paid on Common Stock | | (70.0) | | | (175.0) | |
Other Financing Activities | Other Financing Activities | | 0.5 | | | 0.3 | | Other Financing Activities | | 0.3 | | | 0.5 | |
Net Cash Flows Used for Financing Activities | Net Cash Flows Used for Financing Activities | | (82.6) | | | (94.6) | | Net Cash Flows Used for Financing Activities | | (89.5) | | | (82.6) | |
| Net Increase (Decrease) in Cash and Cash Equivalents | Net Increase (Decrease) in Cash and Cash Equivalents | | (0.1) | | | 0.8 | | Net Increase (Decrease) in Cash and Cash Equivalents | | 24.5 | | | (0.1) | |
Cash and Cash Equivalents at Beginning of Period | Cash and Cash Equivalents at Beginning of Period | | 3.3 | | | 2.0 | | Cash and Cash Equivalents at Beginning of Period | | 1.3 | | | 3.3 | |
Cash and Cash Equivalents at End of Period | Cash and Cash Equivalents at End of Period | | $ | 3.2 | | | $ | 2.8 | | Cash and Cash Equivalents at End of Period | | $ | 25.8 | | | $ | 3.2 | |
| SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 93.9 | | | $ | 97.5 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 101.6 | | | $ | 93.9 | |
Net Cash Paid for Income Taxes | | 11.8 | | | 59.7 | | |
Net Cash Paid (Received) for Income Taxes | | Net Cash Paid (Received) for Income Taxes | | (4.1) | | | 11.8 | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 3.1 | | | 1.9 | | Noncash Acquisitions Under Finance Leases | | 0.8 | | | 3.1 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 59.0 | | | 57.6 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 68.1 | | | 59.0 | |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 0.3 | | | 1.0 | | Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 8.5 | | | 0.3 | |
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage | | 0.6 | | | 2.4 | | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
OHIO POWER COMPANY AND SUBSIDIARIES
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | Retail: | | | | | | | |
Residential | Residential | 4,096 | | | 4,165 | | | 11,261 | | | 11,140 | | Residential | 3,954 | | | 4,096 | | | 11,146 | | | 11,261 | |
Commercial | Commercial | 4,112 | | | 3,781 | | | 11,282 | | | 10,454 | | Commercial | 4,295 | | | 4,112 | | | 11,996 | | | 11,282 | |
Industrial | Industrial | 3,633 | | | 3,380 | | | 10,769 | | | 9,855 | | Industrial | 3,561 | | | 3,633 | | | 10,688 | | | 10,769 | |
Miscellaneous | Miscellaneous | 25 | | | 22 | | | 80 | | | 82 | | Miscellaneous | 25 | | | 25 | | | 79 | | | 80 | |
Total Retail (a) | Total Retail (a) | 11,866 | | | 11,348 | | | 33,392 | | | 31,531 | | Total Retail (a) | 11,835 | | | 11,866 | | | 33,909 | | | 33,392 | |
| Wholesale (b) | Wholesale (b) | 643 | | | 502 | | | 1,691 | | | 1,347 | | Wholesale (b) | 587 | | | 643 | | | 1,723 | | | 1,691 | |
| Total KWhs | Total KWhs | 12,509 | | | 11,850 | | | 35,083 | | | 32,878 | | Total KWhs | 12,422 | | | 12,509 | | | 35,632 | | | 35,083 | |
(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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | 1 | | | 2 | | | 1,993 | | | 1,767 | | Actual – Heating (a) | 8 | | | 1 | | | 2,078 | | | 1,993 | |
Normal – Heating (b) | Normal – Heating (b) | 5 | | | 6 | | | 2,071 | | | 2,086 | | Normal – Heating (b) | 5 | | | 5 | | | 2,077 | | | 2,071 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 787 | | | 809 | | | 1,148 | | | 1,126 | | Actual – Cooling (c) | 755 | | | 787 | | | 1,115 | | | 1,148 | |
Normal – Cooling (b) | Normal – Cooling (b) | 689 | | | 682 | | | 996 | | | 986 | | Normal – Cooling (b) | 688 | | | 689 | | | 989 | | | 996 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Ohio Power Company and Subsidiaries |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 59.056.4 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 15.131.0 | |
Margins from Off-system Sales | | (8.7)21.8 | |
Transmission Revenues | | (2.3)2.1 | |
Other Revenues | | 7.8 (12.6) | |
Total Change in Gross Margin | | 11.942.3 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (6.1)(30.7) | |
Depreciation and Amortization | | (2.8)6.2 | |
Taxes Other Than Income Taxes | | (8.2)(5.0) | |
Interest Income | | (0.2) | |
Carrying Costs Income | | (0.2)(0.1) | |
Allowance for Equity Funds Used During Construction | | (2.6)1.9 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1)1.9 | |
Interest Expense | | (3.5)3.1 | |
Total Change in Expenses and Other | | (23.7)(22.7) | |
| | |
Income Tax Expense | | 9.2 (4.1) | |
| | |
| | |
Third Quarter of 20212022 | | $ | 56.471.9 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
•Retail Margins increased $15$31 million primarily due to the following:
•A $40$21 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 $15 million increase related to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues, and other expense items below.
•A $3$4 million increase in weather-related usage primarily from the industrial and commercial classes.
These increases were partially offset by:
•A $24 million decrease due to the endingend of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $15 million decrease in revenues associated with the Universal Service Fund (USF). This decrease was offset in Other Operation and Maintenance expenses below.decoupling.
•Margins from Off-system Sales decreased $9increased $22 million primarily due to the following:
•A $19$17 million decreaseincrease in deferrals ofoff-system sales at OVEC costs.due to higher market prices. This decreaseincrease was offset in Retail Margins above and Other Revenues below.
This decrease was partially offset by:
•A $10$5 million increase in off-system sales at OVEC.deferrals of OVEC costs. This increase was offset in Retail Margins above and Other Revenues below.
•Other Revenues increased $8decreased $13 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increasedecrease 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 Maintenance expenses increased $6$31 million primarily due to the following:
•A $34$14 million increase in transmission expenses primarily due to an increase in recoverable PJM transmission expenses. This increase was partiallyoffset in Retail Margins above.
•A $5 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
•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:
•A $15Depreciation and Amortization expensesdecreased $6 million primarily due to a decrease in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.recoverable Distribution Investment Rider depreciable expenses. This decrease was offset in Retail Margins above.
•A $15 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $5 million decrease in factored customer accounts receivable expenses primarily due to bad debt expenses and a current year adjustment to allowance for doubtful accounts.
•Taxes Other Than Income Taxesincreased $8$5 million primarily due to an increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•Interest Expense increased $4decreased $3 million primarily due to the retirement of a higher long-term debt balances.rate bond partially offset by the issuance of a lower rate bond in 2021.
•Income Tax Expense decreased $9increased $4 million primarily due to an unfavorable discrete adjustment recorded in 2020 that did not recur in 2021 and a decreaseincrease in pretax book income.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Ohio Power Company and Subsidiaries |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 215.0198.6 | |
| | |
Changes in Gross Margin: | | |
Retail Margins | | 92.1138.7 | |
Margins from Off-system Sales | | (36.0)47.8 | |
Transmission Revenues | | (4.6)(3.2) | |
Other Revenues | | 20.8 (28.8) | |
Total Change in Gross Margin | | 72.3154.5 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (38.6)(125.6) | |
Depreciation and Amortization | | (24.2)11.7 | |
Taxes Other Than Income Taxes | | (28.4)(12.8) | |
Interest Income | | (0.3)0.3 | |
Carrying Costs Income | | (0.2)(0.9) | |
Allowance for Equity Funds Used During Construction | | (1.7)2.7 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.3)5.6 | |
Interest Expense | | (7.8)7.4 | |
Total Change in Expenses and Other | | (101.5)(111.6) | |
| | |
Income Tax Expense | | 12.8(12.4) | |
Equity Earnings of Unconsolidated Subsidiaries | | 0.8 | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 198.6229.9 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
•Retail Margins increased $92$139 million primarily due to the following:
•A $129An $85 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 $71$25 million increase relateddue to various rider revenues. This increase was partially offset in Margins from Off-system Sales, Other Revenues, and other expense items below.
•A $4$12 million increase in usageweather-normalized margins primarily from the commercial class, partially offset by the residential and industrial classes.
These increases were partially offset by:
•A $71An $8 million decreaseincrease in weather-related usage primarily due to the endingend of the Energy Efficiency and Peak Demand Rider in December 2020. This decrease was partially offset in Other Operation and Maintenance expenses below.
•A $43 million decrease in revenues associated with the USF. This decrease was offset in Other Operation and Maintenance expenses below.decoupling.
•Margins from Off-system Sales decreased $36increased $48 million primarily due to the following:
•A $51$54 million increase in off-system sales at OVEC due to higher market prices and volume. This increase was offset in Retail Margins above and Other Revenues below.
This increase was partially offset by:
•A $6 million decrease in deferrals of OVEC costs. This decrease was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues decreased $3 million primarily due to the following:
•An $11 million decrease due to formula rate true-up activity.
This decrease was partially offset by:
•A $16$7 million increase in off-system sales at OVEC. This increase was offset in Retail Margins above and Other Revenues below.
•Transmission Revenues decreased $5 million primarily due to a decreasecontinued investment in net affiliated transmission expenses.assets.
•Other Revenues increased $21decreased $29 million primarily due to third-party Legacy Generation Resource Rider revenue related to the recovery of OVEC costs. This increasedecrease 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 Maintenance expenses increased $39$126 million primarily due to the following:
•A $112$67 million increase in transmission expenses primarily due to the following:
•A $67 million increase in recoverable PJM transmission expenses. This increase was offset in Retail Margins above.
•A $6 million increase in transmission vegetation management expenses.
These increases were partially offset by:
•A $10 million decrease in transmission formula rate true-up activity.
•A $19 million increase in bad debt-related expenses, including $8 million in 2022 due to Bad Debt Rider over-recovery. This increase was offset in Retail Margins above.
•A $15 million increase in recoverable distribution expenses primarily related to vegetation management. This increase was offset in Retail Margins above.
•A $9$14 million increase in PJM expenses primarily related to the annual transmission 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 $45 million decrease in energy efficiency/demand side management expenses. This decrease was partially offset within Retail Margins above.
•A $43 million decrease in remitted USFUniversal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase was offset in Retail Margins above.
•A $10 million increase in employee-related expenses.
•Depreciation and Amortization expensesdecreased $12 million primarily due to the following:
•A $6 million decrease in recoverable smart grid depreciable expenses. This decrease was offset in Retail Margins above.
•A $19$6 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 expensesincreased $24 million primarily due to the following:
•An $8 million increase in amortization of plant primarily related to capitalized software.
•A $7 million increase in depreciation expense due to an increase in therecoverable Distributions Investment Rider depreciable base of transmission and distribution assets.
•A $7 million increase in recoverable DIR depreciation expense.expenses. This increasedecrease was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $28$13 million primarily due to the following:
•A $23 millionan increase in property taxes driven by additional investments in transmission and distribution assets and higher tax rates.
•A $3Non-Service Cost Components of Net Periodic Benefit Cost decreased $6 million primarily due to an increase in excise taxes driven by increased metered KWh usagediscount rates, an increase in 2021. This increase was offsetthe expected return on plan assets and favorable plan returns in Retail Margins above.2021.
•Interest Expense increased $8decreased $7 million primarily due to the retirement of a higher long-term debt balances.rate bond partially offset by the issuance of a lower rate bond in 2021.
•Income Tax Expense decreased $13increased $12 million primarily due to an unfavorableincrease in pretax book income and a favorable 2021 discrete tax adjustment recordedthat did not recur during 2020 and a decrease in pretax book income.2022.
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electricity, Transmission and Distribution | Electricity, Transmission and Distribution | | $ | 761.0 | | | $ | 730.4 | | | $ | 2,167.8 | | | $ | 2,031.4 | | Electricity, Transmission and Distribution | | $ | 1,015.2 | | | $ | 761.0 | | | $ | 2,656.6 | | | $ | 2,167.8 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 4.3 | | | 8.3 | | | 21.9 | | | 33.0 | | Sales to AEP Affiliates | | 4.0 | | | 4.3 | | | 11.6 | | | 21.9 | |
Other Revenues | Other Revenues | | 2.4 | | | 2.3 | | | 6.8 | | | 7.3 | | Other Revenues | | 2.1 | | | 2.4 | | | 6.0 | | | 6.8 | |
TOTAL REVENUES | TOTAL REVENUES | | 767.7 | | | 741.0 | | | 2,196.5 | | | 2,071.7 | | TOTAL REVENUES | | 1,021.3 | | | 767.7 | | | 2,674.2 | | | 2,196.5 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Purchased Electricity for Resale | Purchased Electricity for Resale | | 184.7 | | | 149.3 | | | 513.6 | | | 412.3 | | Purchased Electricity for Resale | | 399.5 | | | 184.7 | | | 875.0 | | | 513.6 | |
Purchased Electricity from AEP Affiliates | Purchased Electricity from AEP Affiliates | | 3.5 | | | 24.1 | | | 48.0 | | | 96.8 | | Purchased Electricity from AEP Affiliates | | — | | | 3.5 | | | 9.8 | | | 48.0 | |
| Other Operation | Other Operation | | 245.1 | | | 244.6 | | | 622.9 | | | 608.5 | | Other Operation | | 267.3 | | | 245.1 | | | 728.2 | | | 622.9 | |
Maintenance | Maintenance | | 39.3 | | | 33.7 | | | 116.4 | | | 92.2 | | Maintenance | | 47.8 | | | 39.3 | | | 136.7 | | | 116.4 | |
Depreciation and Amortization | Depreciation and Amortization | | 76.9 | | | 74.1 | | | 228.6 | | | 204.4 | | Depreciation and Amortization | | 70.7 | | | 76.9 | | | 216.9 | | | 228.6 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 126.0 | | | 117.8 | | | 366.2 | | | 337.8 | | Taxes Other Than Income Taxes | | 131.0 | | | 126.0 | | | 379.0 | | | 366.2 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 675.5 | | | 643.6 | | | 1,895.7 | | | 1,752.0 | | TOTAL EXPENSES | | 916.3 | | | 675.5 | | | 2,345.6 | | | 1,895.7 | |
| OPERATING INCOME | OPERATING INCOME | | 92.2 | | | 97.4 | | | 300.8 | | | 319.7 | | OPERATING INCOME | | 105.0 | | | 92.2 | | | 328.6 | | | 300.8 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Interest Income | Interest Income | | 0.2 | | | 0.4 | | | 0.5 | | | 0.8 | | Interest Income | | 0.2 | | | 0.2 | | | 0.8 | | | 0.5 | |
Carrying Costs Income | Carrying Costs Income | | 0.1 | | | 0.3 | | | 1.1 | | | 1.3 | | Carrying Costs Income | | — | | | 0.1 | | | 0.2 | | | 1.1 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 2.0 | | | 4.6 | | | 7.6 | | | 9.3 | | Allowance for Equity Funds Used During Construction | | 3.9 | | | 2.0 | | | 10.3 | | | 7.6 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 3.7 | | | 3.8 | | | 11.0 | | | 11.3 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 5.6 | | | 3.7 | | | 16.6 | | | 11.0 | |
Interest Expense | Interest Expense | | (32.9) | | | (29.4) | | | (96.2) | | | (88.4) | | Interest Expense | | (29.8) | | | (32.9) | | | (88.8) | | | (96.2) | |
| INCOME BEFORE INCOME TAX EXPENSE | | 65.3 | | | 77.1 | | | 224.8 | | | 254.0 | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | 84.9 | | | 65.3 | | | 267.7 | | | 224.8 | |
| Income Tax Expense | Income Tax Expense | | 8.9 | | | 18.1 | | | 26.2 | | | 39.0 | | Income Tax Expense | | 13.0 | | | 8.9 | | | 38.6 | | | 26.2 | |
Equity Earnings of Unconsolidated Subsidiaries | | Equity Earnings of Unconsolidated Subsidiaries | | — | | | — | | | 0.8 | | | — | |
| NET INCOME | NET INCOME | | $ | 56.4 | | | $ | 59.0 | | | $ | 198.6 | | | $ | 215.0 | | NET INCOME | | $ | 71.9 | | | $ | 56.4 | | | $ | 229.9 | | | $ | 198.6 | |
| The common stock of OPCo is wholly-owned by Parent. | The common stock of OPCo is wholly-owned by Parent. | The common stock of OPCo is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | Common Stock | | Paid-in Capital | | Retained Earnings | | | 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 | | |
| Common Stock Dividends | | (21.8) | | | | (21.8) | | |
Net Income | | 59.0 | | | | 59.0 | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,498.2 | | | | $ | 2,658.2 | | |
| | | | | | | | | | | Common Stock | | Paid-in Capital | | Retained Earnings | | | Total |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,532.7 | | | | $ | 2,692.7 | | TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2020 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,532.7 | | | | $ | 2,692.7 | |
| Common Stock Dividends | Common Stock Dividends | | (21.9) | | | | (21.9) | | Common Stock Dividends | | (21.9) | | | | (21.9) | |
Net Income | Net Income | | 68.2 | | | | 68.2 | | Net Income | | 68.2 | | | | 68.2 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | | 321.2 | | | 838.8 | | | 1,579.0 | | | | 2,739.0 | | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2021 | | 321.2 | | | 838.8 | | | 1,579.0 | | | | 2,739.0 | |
| Common Stock Dividends | Common Stock Dividends | | | | | | (21.9) | | | | (21.9) | | Common Stock Dividends | | | | | | (21.9) | | | | (21.9) | |
Net Income | Net Income | | | | | | 74.0 | | | | 74.0 | | Net Income | | | | | | 74.0 | | | | 74.0 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | | 321.2 | | | 838.8 | | | 1,631.1 | | | | 2,791.1 | | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2021 | | 321.2 | | | 838.8 | | | 1,631.1 | | | | 2,791.1 | |
| Common Stock Dividends | Common Stock Dividends | | (28.1) | | | | (28.1) | | Common Stock Dividends | | (28.1) | | | | (28.1) | |
Net Income | Net Income | | 56.4 | | | | 56.4 | | Net Income | | 56.4 | | | | 56.4 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,659.4 | | | | $ | 2,819.4 | | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,659.4 | | | | $ | 2,819.4 | |
| | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | TOTAL COMMON SHAREHOLDER’S EQUITY – DECEMBER 31, 2021 | | $ | 321.2 | | | $ | 838.8 | | | $ | 1,686.3 | | | | $ | 2,846.3 | |
| Common Stock Dividends | | Common Stock Dividends | | (15.0) | | | | (15.0) | |
Net Income | | Net Income | | 83.2 | | | | 83.2 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – MARCH 31, 2022 | | 321.2 | | | 838.8 | | | 1,754.5 | | | | 2,914.5 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 0.7 | | | | | 0.7 | |
Common Stock Dividends | | Common Stock Dividends | | | | | | (15.0) | | | | (15.0) | |
Net Income | | Net Income | | | | | | 74.8 | | | | 74.8 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – JUNE 30, 2022 | | 321.2 | | | 839.5 | | | 1,814.3 | | | | 2,975.0 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 0.3 | | | | 0.3 |
Common Stock Dividends | | Common Stock Dividends | | (15.0) | | | | (15.0) | |
Net Income | | Net Income | | 71.9 | | | | 71.9 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022 | | TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2022 | | $ | 321.2 | | | $ | 839.8 | | | $ | 1,871.2 | | | | $ | 3,032.2 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 6.8 | | | $ | 7.4 | | Cash and Cash Equivalents | | $ | 10.2 | | | $ | 3.0 | |
Advances to Affiliates | Advances to Affiliates | | 622.9 | | | — | | Advances to Affiliates | | — | | | 42.0 | |
Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 31.0 | | | 50.0 | | Customers | | 60.3 | | | 71.6 | |
Affiliated Companies | Affiliated Companies | | 64.7 | | | 65.1 | | Affiliated Companies | | 105.9 | | | 71.8 | |
Accrued Unbilled Revenues | Accrued Unbilled Revenues | | 15.3 | | | 14.8 | | Accrued Unbilled Revenues | | 14.4 | | | 1.3 | |
Miscellaneous | Miscellaneous | | 5.8 | | | 3.9 | | Miscellaneous | | 0.2 | | | 5.9 | |
Allowance for Uncollectible Accounts | Allowance for Uncollectible Accounts | | (0.6) | | | (0.6) | | Allowance for Uncollectible Accounts | | (0.1) | | | (0.6) | |
Total Accounts Receivable | Total Accounts Receivable | | 116.2 | | | 133.2 | | Total Accounts Receivable | | 180.7 | | | 150.0 | |
Materials and Supplies | Materials and Supplies | | 70.9 | | | 66.9 | | Materials and Supplies | | 97.8 | | | 74.1 | |
Renewable Energy Credits | Renewable Energy Credits | | 31.1 | | | 29.5 | | Renewable Energy Credits | | 33.6 | | | 30.5 | |
| Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 29.6 | | | 19.3 | | Prepayments and Other Current Assets | | 27.2 | | | 27.9 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 877.5 | | | 256.3 | | TOTAL CURRENT ASSETS | | 349.5 | | | 327.5 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Transmission | Transmission | | 2,936.3 | | | 2,831.9 | | Transmission | | 3,070.4 | | | 2,992.8 | |
Distribution | Distribution | | 5,989.2 | | | 5,708.3 | | Distribution | | 6,336.9 | | | 6,070.6 | |
Other Property, Plant and Equipment | Other Property, Plant and Equipment | | 979.9 | | | 899.6 | | Other Property, Plant and Equipment | | 1,038.7 | | | 992.9 | |
Construction Work in Progress | Construction Work in Progress | | 331.7 | | | 362.3 | | Construction Work in Progress | | 491.6 | | | 365.0 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 10,237.1 | | | 9,802.1 | | Total Property, Plant and Equipment | | 10,937.6 | | | 10,421.3 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 2,438.7 | | | 2,350.0 | | Accumulated Depreciation and Amortization | | 2,541.6 | | | 2,458.3 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,798.4 | | | 7,452.1 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 8,396.0 | | | 7,963.0 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 343.8 | | | 385.8 | | Regulatory Assets | | 270.8 | | | 293.0 | |
| Operating Lease Assets | Operating Lease Assets | | 84.2 | | | 92.0 | | Operating Lease Assets | | 74.4 | | | 81.2 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 292.4 | | | 524.2 | | Deferred Charges and Other Noncurrent Assets | | 334.4 | | | 601.1 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 720.4 | | | 1,002.0 | | TOTAL OTHER NONCURRENT ASSETS | | 679.6 | | | 975.3 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 9,396.3 | | | $ | 8,710.4 | | TOTAL ASSETS | | $ | 9,425.1 | | | $ | 9,265.8 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20212022 and December 31, 20202021
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | — | | | $ | 259.2 | | Advances from Affiliates | | $ | 68.8 | | | $ | — | |
Accounts Payable: | Accounts Payable: | | | | | Accounts Payable: | | | | |
General | General | | 169.0 | | | 181.0 | | General | | 314.9 | | | 213.5 | |
Affiliated Companies | Affiliated Companies | | 101.5 | | | 118.4 | | Affiliated Companies | | 126.6 | | | 125.4 | |
Long-term Debt Due Within One Year – Nonaffiliated | Long-term Debt Due Within One Year – Nonaffiliated | | 500.1 | | | 500.1 | | Long-term Debt Due Within One Year – Nonaffiliated | | 0.1 | | | 0.1 | |
Risk Management Liabilities | Risk Management Liabilities | | 3.5 | | | 8.7 | | Risk Management Liabilities | | — | | | 6.7 | |
Customer Deposits | Customer Deposits | | 123.5 | | | 55.1 | | Customer Deposits | | 103.8 | | | 66.4 | |
Accrued Taxes | Accrued Taxes | | 344.8 | | | 631.0 | | Accrued Taxes | | 367.0 | | | 702.4 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 13.1 | | | 13.1 | | Obligations Under Operating Leases | | 13.5 | | | 13.1 | |
Other Current Liabilities | Other Current Liabilities | | 149.6 | | | 139.6 | | Other Current Liabilities | | 159.5 | | | 118.1 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 1,405.1 | | | 1,906.2 | | TOTAL CURRENT LIABILITIES | | 1,154.2 | | | 1,245.7 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 2,968.0 | | | 1,930.1 | | Long-term Debt – Nonaffiliated | | 2,969.8 | | | 2,968.4 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 86.9 | | | 101.6 | | Long-term Risk Management Liabilities | | 45.1 | | | 85.8 | |
Deferred Income Taxes | Deferred Income Taxes | | 1,010.7 | | | 955.1 | | Deferred Income Taxes | | 1,053.2 | | | 1,000.9 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 995.7 | | | 1,005.2 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 1,049.3 | | | 1,020.9 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 71.6 | | | 79.5 | | Obligations Under Operating Leases | | 60.6 | | | 68.6�� | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 38.9 | | | 40.0 | | Deferred Credits and Other Noncurrent Liabilities | | 60.7 | | | 29.2 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 5,171.8 | | | 4,111.5 | | TOTAL NONCURRENT LIABILITIES | | 5,238.7 | | | 5,173.8 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 6,576.9 | | | 6,017.7 | | TOTAL LIABILITIES | | 6,392.9 | | | 6,419.5 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| COMMON SHAREHOLDER’S EQUITY | COMMON SHAREHOLDER’S EQUITY | | | | | COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock –No Par Value: | Common Stock –No Par Value: | | | | | Common Stock –No Par Value: | | | | |
Authorized – 40,000,000 Shares | Authorized – 40,000,000 Shares | | | | | Authorized – 40,000,000 Shares | | | | |
Outstanding – 27,952,473 Shares | Outstanding – 27,952,473 Shares | | 321.2 | | | 321.2 | | Outstanding – 27,952,473 Shares | | 321.2 | | | 321.2 | |
Paid-in Capital | Paid-in Capital | | 838.8 | | | 838.8 | | Paid-in Capital | | 839.8 | | | 838.8 | |
Retained Earnings | Retained Earnings | | 1,659.4 | | | 1,532.7 | | Retained Earnings | | 1,871.2 | | | 1,686.3 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,819.4 | | | 2,692.7 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,032.2 | | | 2,846.3 | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 9,396.3 | | | $ | 8,710.4 | | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 9,425.1 | | | $ | 9,265.8 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
OHIO POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 198.6 | | | $ | 215.0 | | Net Income | | $ | 229.9 | | | $ | 198.6 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | |
Depreciation and Amortization | Depreciation and Amortization | | 228.6 | | | 204.4 | | Depreciation and Amortization | | 216.9 | | | 228.6 | |
Deferred Income Taxes | Deferred Income Taxes | | 29.3 | | | 35.6 | | Deferred Income Taxes | | 29.3 | | | 29.3 | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (7.6) | | | (9.3) | | Allowance for Equity Funds Used During Construction | | (10.3) | | | (7.6) | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | (19.9) | | | 9.7 | | Mark-to-Market of Risk Management Contracts | | (49.6) | | | (19.9) | |
| Property Taxes | Property Taxes | | 234.9 | | | 225.1 | | Property Taxes | | 264.7 | | | 234.9 | |
| Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | (1.1) | | | (93.8) | | Change in Other Noncurrent Assets | | (19.7) | | | (1.1) | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 4.6 | | | (58.3) | | Change in Other Noncurrent Liabilities | | 82.5 | | | 4.6 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | 20.7 | | | 33.4 | | Accounts Receivable, Net | | (27.0) | | | 20.7 | |
Materials and Supplies | Materials and Supplies | | (0.6) | | | (19.8) | | Materials and Supplies | | (11.6) | | | (0.6) | |
Accounts Payable | Accounts Payable | | (19.1) | | | (19.9) | | Accounts Payable | | 87.6 | | | (19.1) | |
Customer Deposits | Customer Deposits | | 68.4 | | | 12.4 | | Customer Deposits | | 37.4 | | | 68.4 | |
Accrued Taxes, Net | Accrued Taxes, Net | | (289.7) | | | (266.2) | | Accrued Taxes, Net | | (344.5) | | | (289.7) | |
Other Current Assets | Other Current Assets | | (7.8) | | | (2.5) | | Other Current Assets | | 11.3 | | | (7.8) | |
Other Current Liabilities | Other Current Liabilities | | 5.8 | | | (35.7) | | Other Current Liabilities | | 25.7 | | | 5.8 | |
Net Cash Flows from Operating Activities | Net Cash Flows from Operating Activities | | 445.1 | | | 230.1 | | Net Cash Flows from Operating Activities | | 522.6 | | | 445.1 | |
| INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (536.6) | | | (604.6) | | Construction Expenditures | | (600.6) | | | (536.6) | |
Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | (622.9) | | | — | | Change in Advances to Affiliates, Net | | 42.0 | | | (622.9) | |
Other Investing Activities | Other Investing Activities | | 10.7 | | | 14.1 | | Other Investing Activities | | 21.3 | | | 10.7 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (1,148.8) | | | (590.5) | | Net Cash Flows Used for Investing Activities | | (537.3) | | | (1,148.8) | |
| FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Capital Contribution from Parent | | Capital Contribution from Parent | | 1.0 | | | — | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 1,037.5 | | | 347.0 | | Issuance of Long-term Debt – Nonaffiliated | | — | | | 1,037.5 | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (259.2) | | | 84.9 | | Change in Advances from Affiliates, Net | | 68.8 | | | (259.2) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (0.1) | | | (0.1) | | Retirement of Long-term Debt – Nonaffiliated | | (0.1) | | | (0.1) | |
Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (3.7) | | | (3.5) | | Principal Payments for Finance Lease Obligations | | (3.6) | | | (3.7) | |
Dividends Paid on Common Stock | Dividends Paid on Common Stock | | (71.9) | | | (65.6) | | Dividends Paid on Common Stock | | (45.0) | | | (71.9) | |
Other Financing Activities | Other Financing Activities | | 0.5 | | | 0.6 | | Other Financing Activities | | 0.8 | | | 0.5 | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 703.1 | | | 363.3 | | Net Cash Flows from Financing Activities | | 21.9 | | | 703.1 | |
| Net Increase (Decrease) in Cash and Cash Equivalents | Net Increase (Decrease) in Cash and Cash Equivalents | | (0.6) | | | 2.9 | | Net Increase (Decrease) in Cash and Cash Equivalents | | 7.2 | | | (0.6) | |
Cash and Cash Equivalents at Beginning of Period | Cash and Cash Equivalents at Beginning of Period | | 7.4 | | | 3.7 | | Cash and Cash Equivalents at Beginning of Period | | 3.0 | | | 7.4 | |
Cash and Cash Equivalents at End of Period | Cash and Cash Equivalents at End of Period | | $ | 6.8 | | | $ | 6.6 | | Cash and Cash Equivalents at End of Period | | $ | 10.2 | | | $ | 6.8 | |
| SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 78.6 | | | $ | 69.7 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 75.8 | | | $ | 78.6 | |
Net Cash Paid (Received) for Income Taxes | | 0.3 | | | (6.0) | | |
Net Cash Paid for Income Taxes | | Net Cash Paid for Income Taxes | | 24.2 | | | 0.3 | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 1.4 | | | 5.2 | | Noncash Acquisitions Under Finance Leases | | 2.1 | | | 1.4 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 66.5 | | | 75.9 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 108.3 | | | 66.5 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | Retail: | | | | | | | |
Residential | Residential | 2,179 | | | 2,019 | | | 5,068 | | | 4,838 | | Residential | 2,293 | | | 2,179 | | | 5,320 | | | 5,068 | |
Commercial | Commercial | 1,476 | | | 1,358 | | | 3,781 | | | 3,549 | | Commercial | 1,547 | | | 1,476 | | | 3,976 | | | 3,781 | |
Industrial | Industrial | 1,566 | | | 1,461 | | | 4,383 | | | 4,299 | | Industrial | 1,616 | | | 1,566 | | | 4,567 | | | 4,383 | |
Miscellaneous | Miscellaneous | 355 | | | 347 | | | 935 | | | 912 | | Miscellaneous | 377 | | | 355 | | | 993 | | | 935 | |
Total Retail | Total Retail | 5,576 | | | 5,185 | | | 14,167 | | | 13,598 | | Total Retail | 5,833 | | | 5,576 | | | 14,856 | | | 14,167 | |
| Wholesale | Wholesale | 162 | | | 130 | | | 350 | | | 261 | | Wholesale | 55 | | | 162 | | | 660 | | | 350 | |
| Total KWhs | Total KWhs | 5,738 | | | 5,315 | | | 14,517 | | | 13,859 | | Total KWhs | 5,888 | | | 5,738 | | | 15,516 | | | 14,517 | |
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | — | | | 1 | | | 1,195 | | | 874 | | Actual – Heating (a) | — | | | — | | | 1,153 | | | 1,195 | |
Normal – Heating (b) | Normal – Heating (b) | 1 | | | 1 | | | 1,078 | | | 1,078 | | Normal – Heating (b) | — | | | 1 | | | 1,085 | | | 1,078 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 1,491 | | | 1,274 | | | 2,075 | | | 1,979 | | Actual – Cooling (c) | 1,678 | | | 1,491 | | | 2,475 | | | 2,075 | |
Normal – Cooling (b) | Normal – Cooling (b) | 1,404 | | | 1,412 | | | 2,079 | | | 2,088 | | Normal – Cooling (b) | 1,407 | | | 1,404 | | | 2,074 | | | 2,079 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Public Service Company of Oklahoma |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Net Income |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 80.393.2 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 29.726.3 | |
Margins from Off-system Sales | | (0.4) | |
Transmission Revenues | | 2.10.5 | |
Other Revenues | | (0.1) | |
Total Change in Gross Margin | | 31.326.7 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (11.9)(24.1) | |
Depreciation and Amortization | | (8.8)(10.6) | |
| | |
InterestTaxes Other Than Income Taxes | | 1.3 | |
| | |
Allowance for Equity Funds Used During Construction | | (0.8)(3.5) | |
| | |
| | |
| | |
Other Income | | 1.2 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 1.0 | |
Interest Expense | | (1.6)(6.2) | |
Total Change in Expenses and Other | | (21.8)(42.2) | |
| | |
Income Tax ExpenseBenefit | | 3.429.2 | |
| | |
Third Quarter of 20212022 | | $ | 93.2106.9 | |
(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 Margins increased $30$26 million primarily due to the following:
•A $22$47 million increase due to a $26 million increase in revenue frombase rate riders. Thisrevenues and a $21 million increase wasin rider revenues. These increases were partially offset in other expense items below.
•A $13An $11 million increase in weather-related usage primarily due to a 17%13% increase in cooling degree days.
•A $3 million increase in weather-normalized retail margins primarily in the commercial class.
These increases were partially offset by:
•A $9$33 million increase in fuel expense due todecrease resulting from the NCWF PTC benefits provided to customers.customers through fuel clause mechanisms. This decrease was partially offset in Income Tax ExpenseBenefit below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $12$24 million primarily due to the following:
•A $10An $8 million increase in recoverable SPPdistribution expenses primarily due to an increase in overhead line maintenance.
•A $7 million increase in transmission expense.expenses primarily due to the following:
•A $36 million increase related to a change in rider recovery, increased transmission investment and increased load.
•A $4 million increase in transmission formula rate true-up activity. This increase was partially offset in Retail Margins above.
These increases were partially offset by:
•A $33 million decrease in recoverable SPP transmission expenses. This decrease was offset in Retail Margins above.
•A $3 million increase primarily due to an increase in maintenance expenses at the NCWF.
•A $3 million increase due to pre-construction costs associated with various renewable projects.
•Depreciation and Amortizationincreased $9$11 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.
•Taxes Other Than Income Taxes increased $4 million primarily due to a new infrastructure fee implemented by the City of Tulsa in March 2022 and increased property taxes. This increase was partially offset in Retail Margins above.
•Interest Expense increased $6 million primarily due to higher long-term debt balances.
•Income Tax Expense Benefitdecreased $3 increased $29 million primarily due to an increase in PTC,PTCs. This increase was partially offset by an increase in pretax book income.Retail Margins above.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Public Service Company of Oklahoma |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Net Income |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 116.4136.6 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 46.882.0 | |
Margin from Off-system Sales | | (0.6) | |
Transmission Revenues | | 5.3 (1.1) | |
Other Revenues | | (5.7) | |
Total Change in Gross Margin | | 45.880.9 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (13.4)(58.2) | |
Depreciation and Amortization | | (19.2)(23.7) | |
Taxes Other Than Income Taxes | | (1.3) | |
Interest Income | | 2.9 (6.5) | |
| | |
Allowance for Equity Funds Used During Construction | | (1.7) | |
| | |
Other Income | | 4.0 | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 0.13.0 | |
Interest Expense | | 1.2 (17.9) | |
Total Change in Expenses and Other | | (31.4)(99.3) | |
| | |
Income Tax ExpenseBenefit | | 5.837.5 | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 136.6155.7 | |
(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 Margins increased $47$82 million primarily due to the following:
•A $41$95 million increase due to a $51 million increase in revenue frombase rate riders. Thisrevenues and a $44 million increase wasin rider revenues. These increases were partially offset in other expense items below.
•A $9$21 million increase in weather-related usage primarily due to a 37% increase in heating degree days and a 5%19% increase in cooling degree days.
•An $8A $12 million increase in weather-normalized retail margins primarily in the commercial and residential classes.industrial classes.
These increases were partially offset by:
•An $11A $46 million increase in fuel expense due todecrease resulting from the NCWF PTC benefits provided to customers. This decrease was offset in Income Tax Expense below.
•Transmission Revenues increased $5 million primarily due to the following:
•A $3 million increase due to increased transmission investments.
•A $2 million increase due to the annual transmission formula rate true-up.
•Other Revenues decreased $6 million primarily due to lower business development revenue.customers through fuel clause mechanisms. This decrease was partially offset in Other Operation and Maintenance expensesIncome Tax Benefit below.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $13$58 million primarily due to the following:
•A $19An $18 million increase in transmission expenses primarily due to a $13the following:
•A $79 million increase due to a change in rider recovery, increased transmission investment and increased load.
This increase was partially offset by:
•A $58 million decrease in recoverable SPP transmission expense and a $5 million increase as a result of the annual transmission formula rate true-up. These increases were partiallyexpenses. This decrease was offset in Retail Margins above.
•A $3 million decrease in transmission formula rate true-up activity. This decrease was partially offset in Retail Margins above.
•A $16 million increase in distribution expenses primarily due to an increase in overhead line maintenance.
•A $15 million increase in generating expenses primarily due to an increase in maintenance expenses at the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.NCWF and Northeastern.
These increases were partially offset by:
•A $5 million decrease in distribution expenses primarily due to a decrease in overhead line maintenance.
•A $5 million decrease in business development expenses. This decrease was partially offset in Other Revenues above.
•Depreciation and Amortization expenses increased $19$24 million primarily due to a higher depreciable base, implementation of new rates and the timing of refunds to customers under rate rider mechanisms.
•Taxes Other Than Income Taxes increased $7 million primarily due to a new infrastructure fee implemented by the City of Tulsa in March 2022 and increased property taxes. This increase was partially offset in Retail Margins above.
•Other Income increased $4 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Interest Expense increased $18 million due to higher long-term debt balances.
•Income Tax ExpenseBenefit decreased $6increased $38 million primarily due to an increase in PTC,PTCs. This increase was partially offset by an increase in pretax book income.Retail Margins above.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | Nine Months Ended |
| | | Three Months Ended | | Nine Months Ended | | | September 30, | | September 30, |
| | | September 30, | | September 30, | |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | Electric Generation, Transmission and Distribution | | $ | 481.3 | | | $ | 379.8 | | | $ | 1,117.4 | | | $ | 976.3 | | Electric Generation, Transmission and Distribution | | $ | 606.5 | | | $ | 481.3 | | | $ | 1,432.9 | | | $ | 1,117.4 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 1.0 | | | 1.4 | | | 3.1 | | | 3.8 | | Sales to AEP Affiliates | | 0.7 | | | 1.0 | | | 2.1 | | | 3.1 | |
Other Revenues | Other Revenues | | 1.5 | | | 1.0 | | | 3.9 | | | 8.0 | | Other Revenues | | 1.0 | | | 1.5 | | | 3.7 | | | 3.9 | |
TOTAL REVENUES | TOTAL REVENUES | | 483.8 | | | 382.2 | | | 1,124.4 | | | 988.1 | | TOTAL REVENUES | | 608.2 | | | 483.8 | | | 1,438.7 | | | 1,124.4 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 195.9 | | | 125.6 | | | 440.8 | | | 350.3 | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 293.6 | | | 195.9 | | | 674.2 | | | 440.8 | |
| Other Operation | Other Operation | | 102.3 | | | 91.7 | | | 262.7 | | | 248.5 | | Other Operation | | 116.3 | | | 102.3 | | | 301.0 | | | 262.7 | |
Maintenance | Maintenance | | 21.2 | | | 19.9 | | | 68.1 | | | 68.9 | | Maintenance | | 31.3 | | | 21.2 | | | 88.0 | | | 68.1 | |
Depreciation and Amortization | Depreciation and Amortization | | 48.9 | | | 40.1 | | | 149.0 | | | 129.8 | | Depreciation and Amortization | | 59.5 | | | 48.9 | | | 172.7 | | | 149.0 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 12.1 | | | 12.1 | | | 37.1 | | | 35.8 | | Taxes Other Than Income Taxes | | 15.6 | | | 12.1 | | | 43.6 | | | 37.1 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 380.4 | | | 289.4 | | | 957.7 | | | 833.3 | | TOTAL EXPENSES | | 516.3 | | | 380.4 | | | 1,279.5 | | | 957.7 | |
| OPERATING INCOME | OPERATING INCOME | | 103.4 | | | 92.8 | | | 166.7 | | | 154.8 | | OPERATING INCOME | | 91.9 | | | 103.4 | | | 159.2 | | | 166.7 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | | | Other Income (Expense): | | | | | | | | |
Interest Income | | 1.3 | | | — | | | 3.0 | | | 0.1 | | |
| Allowance for Equity Funds Used During Construction | | 0.5 | | | 1.3 | | | 1.5 | | | 3.2 | | |
| | Other Income | | Other Income | | 3.0 | | | 1.8 | | | 8.5 | | | 4.5 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 | | | 2.1 | | | 6.4 | | | 6.3 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 3.1 | | | 2.1 | | | 9.4 | | | 6.4 | |
Interest Expense | Interest Expense | | (16.2) | | | (14.6) | | | (44.7) | | | (45.9) | | Interest Expense | | (22.4) | | | (16.2) | | | (62.6) | | | (44.7) | |
| INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | | 91.1 | | | 81.6 | | | 132.9 | | | 118.5 | | |
INCOME BEFORE INCOME TAX BENEFIT | | INCOME BEFORE INCOME TAX BENEFIT | | 75.6 | | | 91.1 | | | 114.5 | | | 132.9 | |
| Income Tax Expense (Benefit) | | (2.1) | | | 1.3 | | | (3.7) | | | 2.1 | | |
Income Tax Benefit | | Income Tax Benefit | | (31.3) | | | (2.1) | | | (41.2) | | | (3.7) | |
| NET INCOME | NET INCOME | | $ | 93.2 | | | $ | 80.3 | | | $ | 136.6 | | | $ | 116.4 | | NET INCOME | | $ | 106.9 | | | $ | 93.2 | | | $ | 155.7 | | | $ | 136.6 | |
| The common stock of PSO is wholly-owned by Parent. | The common stock of PSO is wholly-owned by Parent. | The common stock of PSO is wholly-owned by Parent. |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | Nine Months Ended |
| | | Three Months Ended | | Nine Months Ended | | | September 30, | | September 30, |
| | | September 30, | | September 30, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 93.2 | | | $ | 80.3 | | | $ | 136.6 | | | $ | 116.4 | | Net Income | | $ | 106.9 | | | $ | 93.2 | | | $ | 155.7 | | | $ | 136.6 | |
| OTHER COMPREHENSIVE LOSS, NET OF TAXES | OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | | OTHER COMPREHENSIVE LOSS, NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0 and $(0.2) for the Nine Months Ended September 30, 2021 and 2020, Respectively. | | — | | | (0.3) | | | (0.1) | | | (0.8) | | |
Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $0 and $0 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | — | | | — | | | — | | | (0.1) | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | $ | 93.2 | | | $ | 80.0 | | | $ | 136.5 | | | $ | 115.6 | | TOTAL COMPREHENSIVE INCOME | | $ | 106.9 | | | $ | 93.2 | | | $ | 155.7 | | | $ | 136.5 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER’S EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | | 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 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2020 | | TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2020 | | $ | 157.2 | | | $ | 414.0 | | | $ | 974.3 | | | $ | 0.1 | | | $ | 1,545.6 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 425.0 | | | 425.0 | |
| | ASU 2016-13 Adoption | | 0.3 | | 0.3 | | |
Net Loss | Net Loss | | (10.3) | | | (10.3) | | Net Loss | | (2.7) | | | (2.7) | |
Other Comprehensive Loss | Other Comprehensive Loss | | (0.2) | | | (0.2) | | Other Comprehensive Loss | | (0.1) | | | (0.1) | |
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 | | |
| | | | | | | | | | |
| Net Income | | 80.3 | | | 80.3 | | |
Other Comprehensive Loss | | (0.3) | | | (0.3) | | |
TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2020 | | $ | 157.2 | | | $ | 364.0 | | | $ | 967.7 | | | $ | 0.3 | | | $ | 1,489.2 | | |
| 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 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2021 | | 157.2 | | | 839.0 | | | 971.6 | | | — | | | 1,967.8 | |
| Capital Contribution from Parent | Capital Contribution from Parent | | 200.0 | | | 200.0 | | Capital Contribution from Parent | | 200.0 | | 200.0 | |
Common Stock Dividends | Common Stock Dividends | | | | | | (10.0) | | | | | (10.0) | | Common Stock Dividends | | (10.0) | | | (10.0) | |
Net Income | Net Income | | | | | | 46.1 | | | | | 46.1 | | 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 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2021 | | 157.2 | | | 1,039.0 | | | 1,007.7 | | | — | | | 2,203.9 | |
| | | | | | | | | | | |
Common Stock Dividends | Common Stock Dividends | | (10.0) | | | (10.0) | | Common Stock Dividends | | (10.0) | | | (10.0) | |
Net Income | Net Income | | 93.2 | | | 93.2 | | Net Income | | 93.2 | | | 93.2 | |
| TOTAL COMMON SHAREHOLDER’S EQUITY – SEPTEMBER 30, 2021 | | $ | 157.2 | | | $ | 1,039.0 | | | $ | 1,090.9 | | | $ | — | | | $ | 2,287.1 | | |
TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2021 | | $ | 157.2 | | | $ | 1,039.0 | | | $ | 1,090.9 | | | $ | — | | | $ | 2,287.1 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021 | | TOTAL COMMON SHAREHOLDER'S EQUITY – DECEMBER 31, 2021 | | $ | 157.2 | | | $ | 1,039.0 | | | $ | 1,095.4 | | | $ | — | | | $ | 2,291.6 | |
| | Net Income | | Net Income | | 5.8 | | | 5.8 | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY – MARCH 31, 2022 | | 157.2 | | | 1,039.0 | | | 1,101.2 | | | — | | | 2,297.4 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 2.2 | | | 2.2 | |
| Net Income | | Net Income | | | | | | 43.0 | | | | | 43.0 | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY – JUNE 30, 2022 | | 157.2 | | | 1,041.2 | | | 1,144.2 | | | — | | | 2,342.6 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.1 | | 1.1 | |
Common Stock Dividends | | Common Stock Dividends | | (20.0) | | | (20.0) | |
Net Income | | Net Income | | 106.9 | | | 106.9 | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2022 | | TOTAL COMMON SHAREHOLDER'S EQUITY – SEPTEMBER 30, 2022 | | $ | 157.2 | | | $ | 1,042.3 | | | $ | 1,231.1 | | | $ | — | | | $ | 2,430.6 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 3.6 | | | $ | 2.6 | | Cash and Cash Equivalents | | $ | 5.5 | | | $ | 1.3 | |
Advances to Affiliates | | 59.5 | | | — | | |
| Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 29.7 | | | 30.8 | | Customers | | 44.2 | | | 41.5 | |
Affiliated Companies | Affiliated Companies | | 31.7 | | | 15.6 | | Affiliated Companies | | 93.5 | | | 35.0 | |
Miscellaneous | Miscellaneous | | 0.4 | | | 2.0 | | Miscellaneous | | 5.7 | | | 0.6 | |
| Total Accounts Receivable | Total Accounts Receivable | | 61.8 | | | 48.4 | | Total Accounts Receivable | | 143.4 | | | 77.1 | |
Fuel | Fuel | | 7.6 | | | 17.9 | | Fuel | | 8.4 | | | 14.5 | |
Materials and Supplies | Materials and Supplies | | 54.4 | | | 54.0 | | Materials and Supplies | | 89.0 | | | 56.2 | |
Risk Management Assets | Risk Management Assets | | 18.5 | | | 10.3 | | Risk Management Assets | | 44.5 | | | 12.1 | |
| Accrued Tax Benefits | Accrued Tax Benefits | | 35.7 | | | 10.9 | | Accrued Tax Benefits | | 66.4 | | | 17.6 | |
Regulatory Asset for Under-Recovered Fuel Costs | Regulatory Asset for Under-Recovered Fuel Costs | | 133.4 | | | 30.1 | | Regulatory Asset for Under-Recovered Fuel Costs | | 178.7 | | | 194.6 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 13.1 | | | 7.1 | | Prepayments and Other Current Assets | | 32.8 | | | 13.4 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 387.6 | | | 181.3 | | TOTAL CURRENT ASSETS | | 568.7 | | | 386.8 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Generation | Generation | | 1,795.2 | | | 1,480.7 | | Generation | | 2,386.0 | | | 1,802.4 | |
Transmission | Transmission | | 1,095.9 | | | 1,069.9 | | Transmission | | 1,131.2 | | | 1,107.7 | |
Distribution | Distribution | | 2,959.7 | | | 2,853.0 | | Distribution | | 3,137.3 | | | 3,004.9 | |
Other Property, Plant and Equipment | Other Property, Plant and Equipment | | 427.8 | | | 393.3 | | Other Property, Plant and Equipment | | 464.8 | | | 437.0 | |
Construction Work in Progress | Construction Work in Progress | | 127.7 | | | 128.7 | | Construction Work in Progress | | 225.4 | | | 156.0 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 6,406.3 | | | 5,925.6 | | Total Property, Plant and Equipment | | 7,344.7 | | | 6,508.0 | |
Accumulated Depreciation and Amortization | Accumulated Depreciation and Amortization | | 1,682.6 | | | 1,605.6 | | Accumulated Depreciation and Amortization | | 1,810.5 | | | 1,705.2 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 4,723.7 | | | 4,320.0 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 5,534.2 | | | 4,802.8 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 1,052.3 | | | 375.0 | | Regulatory Assets | | 606.2 | | | 1,037.4 | |
| Employee Benefits and Pension Assets | Employee Benefits and Pension Assets | | 66.2 | | | 65.8 | | Employee Benefits and Pension Assets | | 97.7 | | | 95.2 | |
Operating Lease Assets | Operating Lease Assets | | 70.4 | | | 42.6 | | Operating Lease Assets | | 107.3 | | | 68.9 | |
Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 18.9 | | | 6.0 | | Deferred Charges and Other Noncurrent Assets | | 23.0 | | | 7.9 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 1,207.8 | | | 489.4 | | TOTAL OTHER NONCURRENT ASSETS | | 834.2 | | | 1,209.4 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 6,319.1 | | | $ | 4,990.7 | | TOTAL ASSETS | | $ | 6,937.1 | | | $ | 6,399.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
September 30, 20212022 and December 31, 20202021
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | — | | | $ | 155.4 | | Advances from Affiliates | | $ | 223.5 | | | $ | 72.3 | |
Accounts Payable: | Accounts Payable: | | | | | Accounts Payable: | | | | |
General | General | | 146.4 | | | 107.0 | | General | | 249.0 | | | 157.4 | |
Affiliated Companies | Affiliated Companies | | 32.0 | | | 43.4 | | Affiliated Companies | | 105.0 | | | 51.0 | |
Long-term Debt Due Within One Year – Nonaffiliated | Long-term Debt Due Within One Year – Nonaffiliated | | 0.5 | | | 0.5 | | Long-term Debt Due Within One Year – Nonaffiliated | | 0.5 | | | 125.5 | |
| Risk Management Liabilities | | Risk Management Liabilities | | — | | | 3.7 | |
Customer Deposits | Customer Deposits | | 54.0 | | | 54.8 | | Customer Deposits | | 60.5 | | | 56.2 | |
Accrued Taxes | Accrued Taxes | | 60.9 | | | 26.8 | | Accrued Taxes | | 54.9 | | | 27.0 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 6.9 | | | 6.5 | | Obligations Under Operating Leases | | 8.4 | | | 6.9 | |
| Other Current Liabilities | Other Current Liabilities | | 67.9 | | | 84.2 | | Other Current Liabilities | | 75.0 | | | 62.7 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 368.6 | | | 478.6 | | TOTAL CURRENT LIABILITIES | | 776.8 | | | 562.7 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 1,912.8 | | | 1,373.3 | | Long-term Debt – Nonaffiliated | | 1,913.1 | | | 1,788.0 | |
| Deferred Income Taxes | Deferred Income Taxes | | 764.0 | | | 688.5 | | Deferred Income Taxes | | 794.9 | | | 782.3 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 846.2 | | | 802.2 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 827.9 | | | 835.3 | |
Asset Retirement Obligations | Asset Retirement Obligations | | 55.0 | | | 45.7 | | Asset Retirement Obligations | | 74.6 | | | 57.5 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 63.7 | | | 36.2 | | Obligations Under Operating Leases | | 100.3 | | | 62.2 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 21.7 | | | 20.6 | | Deferred Credits and Other Noncurrent Liabilities | | 18.9 | | | 19.4 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 3,663.4 | | | 2,966.5 | | TOTAL NONCURRENT LIABILITIES | | 3,729.7 | | | 3,544.7 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 4,032.0 | | | 3,445.1 | | TOTAL LIABILITIES | | 4,506.5 | | | 4,107.4 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| COMMON SHAREHOLDER’S EQUITY | COMMON SHAREHOLDER’S EQUITY | | | | | COMMON SHAREHOLDER’S EQUITY | | | | |
Common Stock – Par Value – $15 Per Share: | Common Stock – Par Value – $15 Per Share: | | | | | Common Stock – Par Value – $15 Per Share: | | | | |
Authorized – 11,000,000 Shares | Authorized – 11,000,000 Shares | | | | | Authorized – 11,000,000 Shares | | | | |
Issued – 10,482,000 Shares | Issued – 10,482,000 Shares | | | | | Issued – 10,482,000 Shares | | | | |
Outstanding – 9,013,000 Shares | Outstanding – 9,013,000 Shares | | 157.2 | | | 157.2 | | Outstanding – 9,013,000 Shares | | 157.2 | | | 157.2 | |
Paid-in Capital | Paid-in Capital | | 1,039.0 | | | 414.0 | | Paid-in Capital | | 1,042.3 | | | 1,039.0 | |
Retained Earnings | Retained Earnings | | 1,090.9 | | | 974.3 | | Retained Earnings | | 1,231.1 | | | 1,095.4 | |
Accumulated Other Comprehensive Income (Loss) | | — | | | 0.1 | | |
| TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,287.1 | | | 1,545.6 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 2,430.6 | | | 2,291.6 | |
| TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 6,319.1 | | | $ | 4,990.7 | | TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY | | $ | 6,937.1 | | | $ | 6,399.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 136.6 | | | $ | 116.4 | | Net Income | | $ | 155.7 | | | $ | 136.6 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | |
Depreciation and Amortization | Depreciation and Amortization | | 149.0 | | | 129.8 | | Depreciation and Amortization | | 172.7 | | | 149.0 | |
Deferred Income Taxes | Deferred Income Taxes | | 109.8 | | | (3.2) | | Deferred Income Taxes | | (20.0) | | | 109.8 | |
| Allowance for Equity Funds Used During Construction | | (1.5) | | | (3.2) | | |
| Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | (8.2) | | | (0.3) | | Mark-to-Market of Risk Management Contracts | | (36.1) | | | (8.2) | |
| Property Taxes | Property Taxes | | (10.9) | | | (10.6) | | Property Taxes | | (12.2) | | | (10.9) | |
Deferred Fuel Over/Under-Recovery, Net | Deferred Fuel Over/Under-Recovery, Net | | (776.4) | | | (46.6) | | Deferred Fuel Over/Under-Recovery, Net | | 454.0 | | | (776.4) | |
| Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | (12.8) | | | (7.2) | | Change in Other Noncurrent Assets | | (18.1) | | | (14.3) | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 4.5 | | | 6.1 | | Change in Other Noncurrent Liabilities | | 15.8 | | | 4.5 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | (13.4) | | | (5.6) | | Accounts Receivable, Net | | (66.3) | | | (13.4) | |
Fuel, Materials and Supplies | Fuel, Materials and Supplies | | 9.9 | | | (17.2) | | Fuel, Materials and Supplies | | (25.8) | | | 9.9 | |
Accounts Payable | Accounts Payable | | 16.4 | | | (26.1) | | Accounts Payable | | 150.8 | | | 16.4 | |
Accrued Taxes, Net | Accrued Taxes, Net | | 9.3 | | | 36.9 | | Accrued Taxes, Net | | (20.9) | | | 9.3 | |
Other Current Assets | Other Current Assets | | (5.9) | | | (0.1) | | Other Current Assets | | (19.2) | | | (5.9) | |
Other Current Liabilities | Other Current Liabilities | | (18.4) | | | (16.4) | | Other Current Liabilities | | 11.0 | | | (18.4) | |
Net Cash Flows from (Used for) Operating Activities | Net Cash Flows from (Used for) Operating Activities | | (412.0) | | | 152.7 | | Net Cash Flows from (Used for) Operating Activities | | 741.4 | | | (412.0) | |
| INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (219.6) | | | (256.4) | | Construction Expenditures | | (322.6) | | | (219.6) | |
Change in Advances to Affiliates, Net | Change in Advances to Affiliates, Net | | (59.5) | | | 38.8 | | Change in Advances to Affiliates, Net | | — | | | (59.5) | |
Acquisition of the North Central Wind Energy Facilities | Acquisition of the North Central Wind Energy Facilities | | (297.0) | | | — | | Acquisition of the North Central Wind Energy Facilities | | (549.3) | | | (297.0) | |
Other Investing Activities | Other Investing Activities | | 1.9 | | | 3.9 | | Other Investing Activities | | 2.9 | | | 1.9 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (574.2) | | | (213.7) | | Net Cash Flows Used for Investing Activities | | (869.0) | | | (574.2) | |
| FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Capital Contributions from Parent | | 625.0 | | | — | | |
Capital Contribution from Parent | | Capital Contribution from Parent | | 3.3 | | | 625.0 | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 1,290.0 | | | — | | Issuance of Long-term Debt – Nonaffiliated | | 499.7 | | | 1,290.0 | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (155.4) | | | 77.8 | | Change in Advances from Affiliates, Net | | 151.2 | | | (155.4) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (750.4) | | | (13.0) | | Retirement of Long-term Debt – Nonaffiliated | | (500.4) | | | (750.4) | |
| Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (2.5) | | | (2.7) | | Principal Payments for Finance Lease Obligations | | (2.4) | | | (2.5) | |
Dividends Paid on Common Stock | Dividends Paid on Common Stock | | (20.0) | | | — | | Dividends Paid on Common Stock | | (20.0) | | | (20.0) | |
Other Financing Activities | Other Financing Activities | | 0.5 | | | 0.4 | | Other Financing Activities | | 0.4 | | | 0.5 | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 987.2 | | | 62.5 | | Net Cash Flows from Financing Activities | | 131.8 | | | 987.2 | |
| Net Increase in Cash and Cash Equivalents | Net Increase in Cash and Cash Equivalents | | 1.0 | | | 1.5 | | Net Increase in Cash and Cash Equivalents | | 4.2 | | | 1.0 | |
Cash and Cash Equivalents at Beginning of Period | Cash and Cash Equivalents at Beginning of Period | | 2.6 | | | 1.5 | | Cash and Cash Equivalents at Beginning of Period | | 1.3 | | | 2.6 | |
Cash and Cash Equivalents at End of Period | Cash and Cash Equivalents at End of Period | | $ | 3.6 | | | $ | 3.0 | | Cash and Cash Equivalents at End of Period | | $ | 5.5 | | | $ | 3.6 | |
| SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 42.9 | | | $ | 45.5 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 63.1 | | | $ | 42.9 | |
Net Cash Paid (Received) for Income Taxes | Net Cash Paid (Received) for Income Taxes | | (101.2) | | | (9.5) | | Net Cash Paid (Received) for Income Taxes | | 21.9 | | | (101.2) | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 3.1 | | | 3.0 | | Noncash Acquisitions Under Finance Leases | | 1.7 | | | 3.1 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 44.2 | | | 23.5 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 50.1 | | | 44.2 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions of KWhs) | | (in millions of KWhs) |
Retail: | Retail: | | | | | | | | Retail: | | | | | | | |
Residential | Residential | 1,999 | | | 1,950 | | | 4,973 | | | 4,702 | | Residential | 2,019 | | | 1,999 | | | 5,157 | | | 4,973 | |
Commercial | Commercial | 1,616 | | | 1,552 | | | 4,221 | | | 4,016 | | Commercial | 1,631 | | | 1,616 | | | 4,385 | | | 4,221 | |
Industrial | Industrial | 1,203 | | | 1,185 | | | 3,468 | | | 3,614 | | Industrial | 1,367 | | | 1,203 | | | 3,876 | | | 3,468 | |
Miscellaneous | Miscellaneous | 19 | | | 19 | | | 58 | | | 59 | | Miscellaneous | 17 | | | 19 | | | 55 | | | 58 | |
Total Retail | Total Retail | 4,837 | | | 4,706 | | | 12,720 | | | 12,391 | | Total Retail | 5,034 | | | 4,837 | | | 13,473 | | | 12,720 | |
| Wholesale | Wholesale | 2,170 | | | 1,571 | | | 5,103 | | | 4,081 | | Wholesale | 1,744 | | | 2,170 | | | 5,312 | | | 5,103 | |
| Total KWhs | Total KWhs | 7,007 | | | 6,277 | | | 17,823 | | | 16,472 | | Total KWhs | 6,778 | | | 7,007 | | | 18,785 | | | 17,823 | |
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 | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in degree days) | | (in degree days) |
Actual – Heating (a) | Actual – Heating (a) | — | | | — | | | 789 | | | 522 | | Actual – Heating (a) | — | | | — | | | 704 | | | 789 | |
Normal – Heating (b) | Normal – Heating (b) | 1 | | | 1 | | | 723 | | | 724 | | Normal – Heating (b) | — | | | 1 | | | 726 | | | 723 | |
| Actual – Cooling (c) | Actual – Cooling (c) | 1,478 | | | 1,308 | | | 2,251 | | | 2,051 | | Actual – Cooling (c) | 1,627 | | | 1,478 | | | 2,642 | | | 2,251 | |
Normal – Cooling (b) | Normal – Cooling (b) | 1,416 | | | 1,420 | | | 2,195 | | | 2,200 | | Normal – Cooling (b) | 1,420 | | | 1,416 | | | 2,195 | | | 2,195 | |
(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.
Third Quarter of 20212022 Compared to Third Quarter of 20202021
| | | | | | | | |
Reconciliation of Third Quarter of 20202021 to Third Quarter of 20212022 |
Earnings Attributable to SWEPCo Common Shareholder |
(in millions) |
| | |
Third Quarter of 20202021 | | $ | 87.9108.9 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 16.241.6 | |
Margins from Off-system Sales | | 0.17.2 | |
Transmission Revenues | | 8.17.7 | |
Other Revenues | | 0.70.4 | |
Total Change in Gross Margin | | 25.156.9 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | 2.1 (21.6) | |
| | |
Depreciation and Amortization | | (6.3)(21.0) | |
Taxes Other Than Income Taxes | | (2.2)(5.3) | |
Interest Income | | 2.2 (0.1) | |
Allowance for Equity Funds Used During Construction | | (2.0)(0.4) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | 1.1 | |
| | |
Interest Expense | | (2.4)(3.5) | |
Total Change in Expenses and Other | | (8.6)(50.8) | |
| | |
Income Tax Expense | | 4.524.1 | |
Equity Earnings of Unconsolidated Subsidiary | | 0.3 (0.7) | |
Net Income Attributable to Noncontrolling Interest | | (0.3)1.0 | |
| | |
Third Quarter of 20212022 | | $ | 108.9139.4 | |
(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 Margins increased $16$42 million primarily due to the following:
•A $40 million increase primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
•A $12 million increase in weather-related usage primarily due to a 13%10% increase in cooling degree days.
•A $2$6 million increase in recoverable fuel costsweather-normalized margins primarily due to timing of recovery.the commercial and industrial classes.
These increases were partially offset by:
•A $14 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
•Margins from Off-system Sales increased $7 million due to an increase in Turk Plant merchant sales.
•Transmission Revenues increased $8 million primarily due to continued investment in transmission assets and increased load and transmission investment.load.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses decreased $2increased $22 million primarily due to the following:
•A $7 million increase in transmission expenses primarily due to the following:
•A $6 million decrease in administrative & general expenses and employee-related expenses.
This decrease was partially offset by:
•A $5 million increase in recoverable SPP transmission expense primarily due to increased load.
•Depreciation and Amortization expenses increased $6 million primarily due to a higher depreciable base.
•Income Tax Expense decreased $5 million primarily due to the following:
•A $10 million decrease in state income taxes.
•A $6 millionexpenses. This increase in PTC.
The overall decrease was partially offset by:
•A $3 million increase due to an increase in pretax book income.
•A $3 million decrease in parent company loss benefit.
•A $2 million decrease in amortization of Excess ADIT, partially offset in Retail Margins above.
•A $2 million discrete tax adjustment recognizedincrease in 2021.transmission formula rate true-up activity.
•A $4 million increase in distribution expenses primarily due to vegetation management expenses.
•A $3 million increase related to the assumption of additional Sabine reclamation costs from a joint owner.
•A $2 million increase due to energy efficiency programs. This increase was offset in Retail Margins above.
•A $2 million increase in administrative and general expenses primarily due to rate case expenses and regulatory fees.
•Depreciation and Amortization expenses increased $21 million primarily due to the implementation of new rates in Arkansas and Texas, a higher depreciable base and the NCWF rider. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $5 million primarily due to increased property taxes.
•Interest Expense increased $4 million primarily due to an increase in long-term debt balances and Advances from Affiliates.
•Income Tax Expense decreased $24 million primarily due to an increase in PTCs. This decrease was partially offset in Retail Margins above.
Nine Months Ended September 30, 20212022 Compared to Nine Months Ended September 30, 20202021
| | | | | | | | |
Reconciliation of Nine Months Ended September 30, 20202021 to Nine Months Ended September 30, 20212022 |
Earnings Attributable to SWEPCo Common Shareholder |
(in millions) |
| | |
Nine Months Ended September 30, 20202021 | | $ | 161.8208.1 | |
| | |
Changes in Gross Margin: | | |
Retail Margins (a) | | 62.493.5 | |
Margins from Off-system Sales | | 21.2 (10.3) | |
Transmission Revenues | | 5.418.6 | |
Other Revenues | | 1.90.4 | |
Total Change in Gross Margin | | 90.9102.2 | |
| | |
Changes in Expenses and Other: | | |
Other Operation and Maintenance | | (13.9)(46.4) | |
| | |
Depreciation and Amortization | | (13.5)(34.4) | |
Taxes Other Than Income Taxes | | (12.0)(5.9) | |
Interest Income | | 5.27.0 | |
Allowance for Equity Funds Used During Construction | | (0.3)(2.0) | |
Non-Service Cost Components of Net Periodic Benefit Cost | | (0.1)3.2 | |
| | |
Interest Expense | | (3.3)(9.6) | |
Total Change in Expenses and Other | | (37.9)(88.1) | |
| | |
Income Tax Expense | | (6.5)40.0 | |
Equity Earnings of Unconsolidated Subsidiary | | 0.3 (1.5) | |
Net Income Attributable to Noncontrolling Interest | | (0.5) | |
| | |
Nine Months Ended September 30, 20212022 | | $ | 208.1260.2 | |
(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 Margins increased $62$94 million primarily due to the following:
•An $80 million increase primarily due to base rate revenue increases in Texas and Arkansas and rider increases in all retail jurisdictions. These increases were partially offset in other expense items below.
•A $25$27 million increase in weather-related usage primarily due to a 51%17% increase in heatingcooling degree days, and a 10% increasepartially offset by an 11% decrease in coolingheating degree days.
•A $13An $11 million increase in weather-normalized margins primarily due to the commercial and residential classes, partially offset by the industrial class.
These increases were partially offset by:
•A $16 million decrease resulting from the NCWF PTC benefits provided to customers through fuel clause mechanisms. This decrease was partially offset in Income Tax Benefit below.
•An $8 million decrease in municipal and cooperative revenues primarily due to the February 2021 severe winter weather event.
•A $10 million increase in recoverable fuel costs primarily due to timing of recovery.
•A $6 million increase in municipal and cooperative revenues due to the annual generation formula rate true-up.
•A $6 million increase due to a decrease in the return of Excess ADIT benefits to customers. This increase was offset in Income Tax Expense below.
•Margins from Off-system Sales increased $21decreased $10 million primarily due to Turk Plant merchant sales as a result of the February 2021 severe winter weather event.
•Transmission Revenues increased $5$19 million primarily due to the following:
•A $12$21 million increase due to continued investment in transmission assets and increased load and transmission investment.load.
This increase was partially offset by:
•A $6$3 million decrease due to the annual transmission formula rate true-up.
Expenses and Other and Income Tax Expense changed between years as follows:
•Other Operation and Maintenance expenses increased $14$46 million primarily due to the following:
•A $19$12 million increase in transmission expenseexpenses primarily due to a $10 million increase as a result of the annual formula rate true-up and a $12following:
•A $6 million increase in NITS expenserecoverable SPP transmission expenses. This increase was offset in Retail Margins above.
•A $4 million increase due to increased transmission investment and load.
•A $5$3 million increase due to the prior year capitalization of previously expensed North Central Wind Energy Facilities costs.in transmission vegetation management expenses.
These increases were partially offset by:
•A $6$4 million decrease in formula rate true-up activity.
•A $6 million increase due to pre-construction costs associated with various renewable projects.
•A $6 million increase in generation related expenses.
•A $5 million increase in administrative &and general expenses primarily due to regulatory fees and employee-related expenses.
•A $2$5 million decreaseincrease in overhead line maintenancedistribution expenses primarily due to vegetation management expenses.
•A $5 million increase due to energy efficiency programs. This increase was offset in Retail Margins above.
•A $3 million increase related to storm restoration.the assumption of additional Sabine reclamation costs from a joint owner.
•Depreciation and Amortization expenses increased $14$34 million primarily due to the implementation of new rates in Arkansas and Texas, a higher depreciable base.base and the NCWF rider. This increase was partially offset in Retail Margins above.
•Taxes Other Than Income Taxes increased $12$6 million primarily due to increased property taxes resulting from the expiration of the Louisiana Industrial Tax Exemption related to Stall Plant.taxes.
•Interest Income increased $5$7 million primarily related to carrying charges on regulatory assets resulting from the February 2021 severe winter weather event.
•Interest Expense increased $3$10 million primarily due to higheran increase in long-term debt balances.balances and Advances from Affiliates.
•Income Tax Expense increased $7decreased $40 million primarily due to the following:
•An $11 million increase due to an increase in PTCs, partially offset by an increase in pretax book income.
•A $10 millionincome and an increase in state tax expense. The decrease in amortization of Excess ADIT,Income Tax Expense driven by the increase in PTCs is partially offset in Retail Margins above.
•A $3 million decrease in parent company loss benefit.
•A $2 million decrease in flow through tax benefits.
•A $2 million discrete tax adjustment recognized in 2021.
The overall increase was partially offset by:
•A $12 million decrease in state income tax expense.
•A $10 million increase in PTC.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
REVENUES | REVENUES | | | | | | | | | REVENUES | | | | | | | | |
Electric Generation, Transmission and Distribution | Electric Generation, Transmission and Distribution | | $ | 570.1 | | | $ | 505.7 | | | $ | 1,596.6 | | | $ | 1,284.3 | | Electric Generation, Transmission and Distribution | | $ | 698.8 | | | $ | 570.1 | | | $ | 1,703.7 | | | $ | 1,596.6 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | 13.5 | | | 10.9 | | | 32.2 | | | 31.5 | | Sales to AEP Affiliates | | 18.2 | | | 13.5 | | | 43.7 | | | 32.2 | |
| Other Revenues | Other Revenues | | 0.5 | | | 0.7 | | | 1.5 | | | 2.4 | | Other Revenues | | 0.5 | | | 0.5 | | | 1.5 | | | 1.5 | |
TOTAL REVENUES | TOTAL REVENUES | | 584.1 | | | 517.3 | | | 1,630.3 | | | 1,318.2 | | TOTAL REVENUES | | 717.5 | | | 584.1 | | | 1,748.9 | | | 1,630.3 | |
| EXPENSES | EXPENSES | | | | | | | | | EXPENSES | | | | | | | | |
Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 214.4 | | | 172.7 | | | 652.7 | | | 431.5 | | Purchased Electricity, Fuel and Other Consumables Used for Electric Generation | | 290.9 | | | 214.4 | | | 669.1 | | | 652.7 | |
| Other Operation | Other Operation | | 91.7 | | | 96.8 | | | 270.6 | | | 259.0 | | Other Operation | | 114.1 | | | 91.7 | | | 308.7 | | | 270.6 | |
Maintenance | Maintenance | | 33.7 | | | 30.7 | | | 99.5 | | | 97.2 | | Maintenance | | 32.9 | | | 33.7 | | | 107.8 | | | 99.5 | |
| Depreciation and Amortization | Depreciation and Amortization | | 74.8 | | | 68.5 | | | 217.4 | | | 203.9 | | Depreciation and Amortization | | 95.8 | | | 74.8 | | | 251.8 | | | 217.4 | |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes | | 28.9 | | | 26.7 | | | 89.0 | | | 77.0 | | Taxes Other Than Income Taxes | | 34.2 | | | 28.9 | | | 94.9 | | | 89.0 | |
TOTAL EXPENSES | TOTAL EXPENSES | | 443.5 | | | 395.4 | | | 1,329.2 | | | 1,068.6 | | TOTAL EXPENSES | | 567.9 | | | 443.5 | | | 1,432.3 | | | 1,329.2 | |
| OPERATING INCOME | OPERATING INCOME | | 140.6 | | | 121.9 | | | 301.1 | | | 249.6 | | OPERATING INCOME | | 149.6 | | | 140.6 | | | 316.6 | | | 301.1 | |
| Other Income (Expense): | Other Income (Expense): | | | | | | | Other Income (Expense): | | | | | | |
Interest Income | Interest Income | | 2.8 | | | 0.6 | | | 6.9 | | | 1.7 | | Interest Income | | 2.7 | | | 2.8 | | | 13.9 | | | 6.9 | |
Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | 1.4 | | | 3.4 | | | 5.4 | | | 5.7 | | Allowance for Equity Funds Used During Construction | | 1.0 | | | 1.4 | | | 3.4 | | | 5.4 | |
Non-Service Cost Components of Net Periodic Benefit Cost | Non-Service Cost Components of Net Periodic Benefit Cost | | 2.1 | | | 2.1 | | | 6.2 | | | 6.3 | | Non-Service Cost Components of Net Periodic Benefit Cost | | 3.2 | | | 2.1 | | | 9.4 | | | 6.2 | |
| Interest Expense | Interest Expense | | (31.7) | | | (29.3) | | | (92.4) | | | (89.1) | | Interest Expense | | (35.2) | | | (31.7) | | | (102.0) | | | (92.4) | |
| INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | 115.2 | | | 98.7 | | | 227.2 | | | 174.2 | | |
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) AND EQUITY EARNINGS | | 121.3 | | | 115.2 | | | 241.3 | | | 227.2 | |
| Income Tax Expense | | 6.3 | | | 10.8 | | | 19.0 | | | 12.5 | | |
Income Tax Expense (Benefit) | | Income Tax Expense (Benefit) | | (17.8) | | | 6.3 | | | (21.0) | | | 19.0 | |
Equity Earnings of Unconsolidated Subsidiary | Equity Earnings of Unconsolidated Subsidiary | | 1.0 | | | 0.7 | | | 2.5 | | | 2.2 | | Equity Earnings of Unconsolidated Subsidiary | | 0.3 | | | 1.0 | | | 1.0 | | | 2.5 | |
| NET INCOME | NET INCOME | | 109.9 | | | 88.6 | | | 210.7 | | | 163.9 | | NET INCOME | | 139.4 | | | 109.9 | | | 263.3 | | | 210.7 | |
| Net Income Attributable to Noncontrolling Interest | Net Income Attributable to Noncontrolling Interest | | 1.0 | | | 0.7 | | | 2.6 | | | 2.1 | | Net Income Attributable to Noncontrolling Interest | | — | | | 1.0 | | | 3.1 | | | 2.6 | |
| EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 108.9 | | | $ | 87.9 | | | $ | 208.1 | | | $ | 161.8 | | EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 139.4 | | | $ | 108.9 | | | $ | 260.2 | | | $ | 208.1 | |
| The common stock of SWEPCo is wholly-owned by Parent. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, | | | September 30, | | September 30, |
| | | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
Net Income | Net Income | | $ | 109.9 | | | $ | 88.6 | | | $ | 210.7 | | | $ | 163.9 | | Net Income | | $ | 139.4 | | | $ | 109.9 | | | $ | 263.3 | | | $ | 210.7 | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES | | | | | | | | |
Cash Flow Hedges, Net of Tax of $0.1 and $0.1 for the Three Months Ended September 30, 2021 and 2020, Respectively, and $0.3 and $0.3 for the Nine Months Ended September 30, 2021 and 2020, Respectively | | 0.3 | | | 0.4 | | | 1.1 | | | 1.1 | | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2021 and 2020, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2021 and 2020, Respectively | | (0.4) | | | (0.4) | | | (1.2) | | | (1.1) | | |
Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Cash Flow Hedges, Net of Tax of $0 and $0.1 for the Three Months Ended September 30, 2022 and 2021, Respectively, and $0 and $0.3 for the Nine Months Ended September 30, 2022 and 2021, Respectively | | — | | | 0.3 | | | — | | | 1.1 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | Amortization of Pension and OPEB Deferred Costs, Net of Tax of $(0.1) and $(0.1) for the Three Months Ended September 30, 2022 and 2021, Respectively, and $(0.3) and $(0.3) for the Nine Months Ended September 30, 2022 and 2021, Respectively | | (0.4) | | | (0.4) | | | (1.2) | | | (1.2) | |
| TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | | (0.1) | | | — | | | (0.1) | | | — | | |
TOTAL OTHER COMPREHENSIVE LOSS | | TOTAL OTHER COMPREHENSIVE LOSS | | (0.4) | | | (0.1) | | | (1.2) | | | (0.1) | |
| TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | 109.8 | | | 88.6 | | | 210.6 | | | 163.9 | | TOTAL COMPREHENSIVE INCOME | | 139.0 | | | 109.8 | | | 262.1 | | | 210.6 | |
| Total Comprehensive Income Attributable to Noncontrolling Interest | Total Comprehensive Income Attributable to Noncontrolling Interest | | 1.0 | | | 0.7 | | | 2.6 | | | 2.1 | | Total Comprehensive Income Attributable to Noncontrolling Interest | | — | | | 1.0 | | | 3.1 | | | 2.6 | |
| TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 108.8 | | | $ | 87.9 | | | $ | 208.0 | | | $ | 161.8 | | TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 139.0 | | | $ | 108.8 | | | $ | 259.0 | | | $ | 208.0 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | SWEPCo Common Shareholder | | | | | | 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 | | |
| Reverse Common Stock Split | (135.6) | | | 135.6 | | | — | | |
| Common Stock Dividends – Nonaffiliated | | (0.4) | | | (0.4) | | |
Net Income | | 87.9 | | | 0.7 | | | 88.6 | | |
| TOTAL EQUITY – SEPTEMBER 30, 2020 | $ | 0.1 | | | $ | 812.2 | | | $ | 1,792.9 | | | $ | (1.3) | | | $ | 0.4 | | | $ | 2,604.3 | | |
| | | | | | | | | | | | | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Total |
TOTAL EQUITY – DECEMBER 31, 2020 | TOTAL EQUITY – DECEMBER 31, 2020 | $ | 0.1 | | | $ | 812.2 | | | $ | 1,811.9 | | | $ | 1.9 | | | $ | 1.6 | | | $ | 2,627.7 | | TOTAL EQUITY – DECEMBER 31, 2020 | $ | 0.1 | | | $ | 812.2 | | | $ | 1,811.9 | | | $ | 1.9 | | | $ | 1.6 | | | $ | 2,627.7 | |
| Capital Contribution from Parent | Capital Contribution from Parent | | 100.0 | | 100.0 | | Capital Contribution from Parent | | 100.0 | | 100.0 | |
| Common Stock Dividends – Nonaffiliated | Common Stock Dividends – Nonaffiliated | | (1.0) | | | (1.0) | | Common Stock Dividends – Nonaffiliated | | (1.0) | | | (1.0) | |
| Net Income | Net Income | | 62.4 | | | 1.0 | | | 63.4 | | Net Income | | 62.4 | | | 1.0 | | | 63.4 | |
| TOTAL EQUITY – MARCH 31, 2021 | TOTAL EQUITY – MARCH 31, 2021 | 0.1 | | | 912.2 | | | 1,874.3 | | | 1.9 | | | 1.6 | | | 2,790.1 | | TOTAL EQUITY – MARCH 31, 2021 | 0.1 | | | 912.2 | | | 1,874.3 | | | 1.9 | | | 1.6 | | | 2,790.1 | |
| Capital Contribution from Parent | Capital Contribution from Parent | | 75.0 | | 75.0 | | Capital Contribution from Parent | | 75.0 | | 75.0 | |
| Common Stock Dividends – Nonaffiliated | Common Stock Dividends – Nonaffiliated | | | | | | | | | (0.6) | | | (0.6) | | Common Stock Dividends – Nonaffiliated | | | | | | | | | (0.6) | | | (0.6) | |
Net Income | Net Income | | | | | 36.8 | | | | | 0.6 | | | 37.4 | | Net Income | | | | | 36.8 | | | | | 0.6 | | | 37.4 | |
| TOTAL EQUITY – JUNE 30, 2021 | TOTAL EQUITY – JUNE 30, 2021 | 0.1 | | | 987.2 | | | 1,911.1 | | | 1.9 | | | 1.6 | | | 2,901.9 | | TOTAL EQUITY – JUNE 30, 2021 | 0.1 | | | 987.2 | | | 1,911.1 | | | 1.9 | | | 1.6 | | | 2,901.9 | |
| Capital Contribution from Parent | Capital Contribution from Parent | | 105.0 | | | 105.0 | | Capital Contribution from Parent | | 105.0 | | | 105.0 | |
| | Common Stock Dividends – Nonaffiliated | Common Stock Dividends – Nonaffiliated | | (2.2) | | | (2.2) | | Common Stock Dividends – Nonaffiliated | | (2.2) | | | (2.2) | |
Net Income | Net Income | | 108.9 | | | 1.0 | | | 109.9 | | Net Income | | 108.9 | | | 1.0 | | | 109.9 | |
Other Comprehensive Loss | Other Comprehensive Loss | | (0.1) | | | (0.1) | | Other Comprehensive Loss | | (0.1) | | | (0.1) | |
TOTAL EQUITY – SEPTEMBER 30, 2021 | TOTAL EQUITY – SEPTEMBER 30, 2021 | $ | 0.1 | | | $ | 1,092.2 | | | $ | 2,020.0 | | | $ | 1.8 | | | $ | 0.4 | | | $ | 3,114.5 | | TOTAL EQUITY – SEPTEMBER 30, 2021 | $ | 0.1 | | | $ | 1,092.2 | | | $ | 2,020.0 | | | $ | 1.8 | | | $ | 0.4 | | | $ | 3,114.5 | |
| TOTAL EQUITY – DECEMBER 31, 2021 | | TOTAL EQUITY – DECEMBER 31, 2021 | $ | 0.1 | | | $ | 1,092.2 | | | $ | 2,050.9 | | | $ | 6.7 | | | $ | (0.1) | | | $ | 3,149.8 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 350.0 | | | 350.0 | |
| Common Stock Dividends – Nonaffiliated | | Common Stock Dividends – Nonaffiliated | | (0.8) | | | (0.8) | |
| Net Income | | Net Income | | 44.1 | | | 1.0 | | | 45.1 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | (0.3) | | | (0.3) | |
TOTAL EQUITY – MARCH 31, 2022 | | TOTAL EQUITY – MARCH 31, 2022 | 0.1 | | | 1,442.2 | | | 2,095.0 | | | 6.4 | | | 0.1 | | | 3,543.8 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 2.2 | | 2.2 | |
Common Stock Dividends | | Common Stock Dividends | | | | | (12.5) | | | | | | | (12.5) | |
Common Stock Dividends – Nonaffiliated | | Common Stock Dividends – Nonaffiliated | | | | | | | | | (0.7) | | | (0.7) | |
Net Income | | Net Income | | | | | 76.7 | | | | | 2.1 | | | 78.8 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | | | | | | (0.5) | | | | | (0.5) | |
TOTAL EQUITY – JUNE 30, 2022 | | TOTAL EQUITY – JUNE 30, 2022 | 0.1 | | | 1,444.4 | | | 2,159.2 | | | 5.9 | | | 1.5 | | | 3,611.1 | |
| Capital Contribution from Parent | | Capital Contribution from Parent | | 1.1 | | | 1.1 | |
Common Stock Dividends | | Common Stock Dividends | | (45.0) | | | (45.0) | |
Common Stock Dividends – Nonaffiliated | | Common Stock Dividends – Nonaffiliated | | (1.1) | | | (1.1) | |
Net Income | | Net Income | | 139.4 | | | — | | | 139.4 | |
Other Comprehensive Loss | | Other Comprehensive Loss | | (0.4) | | | (0.4) | |
TOTAL EQUITY – SEPTEMBER 30, 2022 | | TOTAL EQUITY – SEPTEMBER 30, 2022 | $ | 0.1 | | | $ | 1,445.5 | | | $ | 2,253.6 | | | $ | 5.5 | | | $ | 0.4 | | | $ | 3,705.1 | |
| | | | | |
| |
| |
| |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 20212022 and December 31, 20202021
(in millions)
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
CURRENT ASSETS | CURRENT ASSETS | | | | | CURRENT ASSETS | | | | |
Cash and Cash Equivalents (September 30, 2021 and December 31, 2020 Amounts Include $41 and $10.1, Respectively, Related to Sabine) | | $ | 45.0 | | | $ | 13.2 | | |
Cash and Cash Equivalents (September 30, 2022 and December 31, 2021 Amounts Include $79.2 and $49.9, Respectively, Related to Sabine) | | Cash and Cash Equivalents (September 30, 2022 and December 31, 2021 Amounts Include $79.2 and $49.9, Respectively, Related to Sabine) | | $ | 84.4 | | | $ | 51.2 | |
Advances to Affiliates | Advances to Affiliates | | 2.1 | | | 2.1 | | Advances to Affiliates | | 2.1 | | | 155.9 | |
Accounts Receivable: | Accounts Receivable: | | | | | Accounts Receivable: | | | | |
Customers | Customers | | 76.2 | | | 27.1 | | Customers | | 31.9 | | | 35.8 | |
Affiliated Companies | Affiliated Companies | | 35.6 | | | 25.1 | | Affiliated Companies | | 53.8 | | | 38.3 | |
Miscellaneous | Miscellaneous | | 23.3 | | | 12.7 | | Miscellaneous | | 18.6 | | | 12.3 | |
| Total Accounts Receivable | Total Accounts Receivable | | 135.1 | | | 64.9 | | Total Accounts Receivable | | 104.3 | | | 86.4 | |
Fuel (September 30, 2021 and December 31, 2020 Amounts Include $6.7 and $35.2, Respectively, Related to Sabine) | | 95.4 | | | 191.1 | | |
Materials and Supplies (September 30, 2021 and December 31, 2020 Amounts Include $15.9 and $23.3, Respectively, Related to Sabine) | | 86.8 | | | 95.8 | | |
Fuel (September 30, 2022 and December 31, 2021 Amounts Include $9.9 and $13.1, Respectively, Related to Sabine) | | Fuel (September 30, 2022 and December 31, 2021 Amounts Include $9.9 and $13.1, Respectively, Related to Sabine) | | 55.3 | | | 82.2 | |
Materials and Supplies (September 30, 2022 and December 31, 2021 Amounts Include $7.2 and $12, Respectively, Related to Sabine) | | Materials and Supplies (September 30, 2022 and December 31, 2021 Amounts Include $7.2 and $12, Respectively, Related to Sabine) | | 85.3 | | | 81.9 | |
Risk Management Assets | Risk Management Assets | | 17.5 | | | 3.2 | | Risk Management Assets | | 36.4 | | | 9.8 | |
| Accrued Tax Benefits | Accrued Tax Benefits | | 19.8 | | | 29.9 | | Accrued Tax Benefits | | 88.4 | | | 17.8 | |
Regulatory Asset for Under-Recovered Fuel Costs | Regulatory Asset for Under-Recovered Fuel Costs | | 38.7 | | | 2.6 | | Regulatory Asset for Under-Recovered Fuel Costs | | 333.8 | | | 143.9 | |
Prepayments and Other Current Assets | Prepayments and Other Current Assets | | 20.8 | | | 25.2 | | Prepayments and Other Current Assets | | 50.0 | | | 39.4 | |
TOTAL CURRENT ASSETS | TOTAL CURRENT ASSETS | | 461.2 | | | 428.0 | | TOTAL CURRENT ASSETS | | 840.0 | | | 668.5 | |
| PROPERTY, PLANT AND EQUIPMENT | PROPERTY, PLANT AND EQUIPMENT | | | | | PROPERTY, PLANT AND EQUIPMENT | | | | |
Electric: | Electric: | | | | | Electric: | | | | |
Generation | Generation | | 5,065.5 | | | 4,681.4 | | Generation | | 5,454.6 | | | 4,734.5 | |
Transmission | Transmission | | 2,264.6 | | | 2,165.7 | | Transmission | | 2,380.3 | | | 2,316.9 | |
Distribution | Distribution | | 2,499.2 | | | 2,382.5 | | Distribution | | 2,622.5 | | | 2,514.3 | |
Other Property, Plant and Equipment (September 30, 2021 and December 31, 2020 Amounts Include $220.2 and $223.7, Respectively, Related to Sabine) | | 817.6 | | | 788.8 | | |
Other Property, Plant and Equipment (September 30, 2022 and December 31, 2021 Amounts Include $219.9 and $219.9, Respectively, Related to Sabine) | | Other Property, Plant and Equipment (September 30, 2022 and December 31, 2021 Amounts Include $219.9 and $219.9, Respectively, Related to Sabine) | | 801.4 | | | 764.0 | |
Construction Work in Progress | Construction Work in Progress | | 195.5 | | | 228.3 | | Construction Work in Progress | | 345.3 | | | 240.7 | |
Total Property, Plant and Equipment | Total Property, Plant and Equipment | | 10,842.4 | | | 10,246.7 | | Total Property, Plant and Equipment | | 11,604.1 | | | 10,570.4 | |
Accumulated Depreciation and Amortization (September 30, 2021 and December 31, 2020 Amounts Include $156.7 and $126.5, Respectively, Related to Sabine) | | 3,478.5 | | | 3,158.5 | | |
Accumulated Depreciation and Amortization (September 30, 2022 and December 31, 2021 Amounts Include $201.8 and $168.1, Respectively, Related to Sabine) | | Accumulated Depreciation and Amortization (September 30, 2022 and December 31, 2021 Amounts Include $201.8 and $168.1, Respectively, Related to Sabine) | | 3,444.2 | | | 3,170.3 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 7,363.9 | | | 7,088.2 | | TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | 8,159.9 | | | 7,400.1 | |
| OTHER NONCURRENT ASSETS | OTHER NONCURRENT ASSETS | | | | | OTHER NONCURRENT ASSETS | | | | |
Regulatory Assets | Regulatory Assets | | 1,068.0 | | | 403.1 | | Regulatory Assets | | 992.4 | | | 1,005.3 | |
Long-term Risk Management Assets | | 2.1 | | | — | | |
| | Deferred Charges and Other Noncurrent Assets | Deferred Charges and Other Noncurrent Assets | | 277.3 | | | 234.8 | | Deferred Charges and Other Noncurrent Assets | | 300.8 | | | 251.8 | |
TOTAL OTHER NONCURRENT ASSETS | TOTAL OTHER NONCURRENT ASSETS | | 1,347.4 | | | 637.9 | | TOTAL OTHER NONCURRENT ASSETS | | 1,293.2 | | | 1,257.1 | |
| TOTAL ASSETS | TOTAL ASSETS | | $ | 9,172.5 | | | $ | 8,154.1 | | TOTAL ASSETS | | $ | 10,293.1 | | | $ | 9,325.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 20212022 and December 31, 20202021
(Unaudited)
| | | | September 30, | | December 31, | | | September 30, | | December 31, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
CURRENT LIABILITIES | CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Advances from Affiliates | Advances from Affiliates | | $ | 122.9 | | | $ | 124.6 | | Advances from Affiliates | | $ | 156.3 | | | $ | — | |
Accounts Payable: | Accounts Payable: | | | | | Accounts Payable: | | | | |
General | General | | 114.7 | | | 135.9 | | General | | 206.2 | | | 163.6 | |
Affiliated Companies | Affiliated Companies | | 43.4 | | | 43.0 | | Affiliated Companies | | 100.5 | | | 61.4 | |
Short-term Debt – Nonaffiliated | | — | | | 35.0 | | |
| Long-term Debt Due Within One Year – Nonaffiliated | Long-term Debt Due Within One Year – Nonaffiliated | | 381.2 | | | 106.2 | | Long-term Debt Due Within One Year – Nonaffiliated | | 6.2 | | | 6.2 | |
Risk Management Liabilities | Risk Management Liabilities | | — | | | 0.7 | | Risk Management Liabilities | | — | | | 2.1 | |
Customer Deposits | Customer Deposits | | 60.7 | | | 61.3 | | Customer Deposits | | 65.3 | | | 62.4 | |
Accrued Taxes | Accrued Taxes | | 103.1 | | | 41.0 | | Accrued Taxes | | 113.8 | | | 44.3 | |
Accrued Interest | Accrued Interest | | 23.0 | | | 34.6 | | Accrued Interest | | 30.3 | | | 36.0 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 8.3 | | | 7.9 | | Obligations Under Operating Leases | | 8.4 | | | 8.1 | |
| Other Current Liabilities | Other Current Liabilities | | 119.6 | | | 173.4 | | Other Current Liabilities | | 129.0 | | | 154.6 | |
TOTAL CURRENT LIABILITIES | TOTAL CURRENT LIABILITIES | | 976.9 | | | 763.6 | | TOTAL CURRENT LIABILITIES | | 816.0 | | | 538.7 | |
| NONCURRENT LIABILITIES | NONCURRENT LIABILITIES | | | | | NONCURRENT LIABILITIES | | | | |
Long-term Debt – Nonaffiliated | Long-term Debt – Nonaffiliated | | 2,748.7 | | | 2,530.2 | | Long-term Debt – Nonaffiliated | | 3,386.2 | | | 3,389.0 | |
Long-term Risk Management Liabilities | | — | | | 1.0 | | |
| Deferred Income Taxes | Deferred Income Taxes | | 1,067.6 | | | 1,017.6 | | Deferred Income Taxes | | 1,112.0 | | | 1,087.6 | |
Regulatory Liabilities and Deferred Investment Tax Credits | Regulatory Liabilities and Deferred Investment Tax Credits | | 879.8 | | | 863.4 | | Regulatory Liabilities and Deferred Investment Tax Credits | | 818.2 | | | 806.9 | |
Asset Retirement Obligations | Asset Retirement Obligations | | 193.4 | | | 193.7 | | Asset Retirement Obligations | | 247.5 | | | 192.7 | |
Employee Benefits and Pension Obligations | Employee Benefits and Pension Obligations | | 23.8 | | | 18.6 | | Employee Benefits and Pension Obligations | | 23.2 | | | 20.3 | |
| Obligations Under Operating Leases | Obligations Under Operating Leases | | 79.2 | | | 44.1 | | Obligations Under Operating Leases | | 122.5 | | | 77.7 | |
Deferred Credits and Other Noncurrent Liabilities | Deferred Credits and Other Noncurrent Liabilities | | 88.6 | | | 94.2 | | Deferred Credits and Other Noncurrent Liabilities | | 62.4 | | | 63.0 | |
TOTAL NONCURRENT LIABILITIES | TOTAL NONCURRENT LIABILITIES | | 5,081.1 | | | 4,762.8 | | TOTAL NONCURRENT LIABILITIES | | 5,772.0 | | | 5,637.2 | |
| TOTAL LIABILITIES | TOTAL LIABILITIES | | 6,058.0 | | | 5,526.4 | | TOTAL LIABILITIES | | 6,588.0 | | | 6,175.9 | |
| Rate Matters (Note 4) | Rate Matters (Note 4) | | 0 | | 0 | Rate Matters (Note 4) | |
Commitments and Contingencies (Note 5) | Commitments and Contingencies (Note 5) | | 0 | | 0 | Commitments and Contingencies (Note 5) | |
| EQUITY | EQUITY | | | | | EQUITY | | | | |
Common Stock – Par Value – $18 Per Share: | Common Stock – Par Value – $18 Per Share: | | | | | Common Stock – Par Value – $18 Per Share: | | | | |
Authorized – 3,680 Shares | Authorized – 3,680 Shares | | | | | Authorized – 3,680 Shares | | | | |
Outstanding – 3,680 Shares | Outstanding – 3,680 Shares | | 0.1 | | | 0.1 | | Outstanding – 3,680 Shares | | 0.1 | | | 0.1 | |
Paid-in Capital | Paid-in Capital | | 1,092.2 | | | 812.2 | | Paid-in Capital | | 1,445.5 | | | 1,092.2 | |
Retained Earnings | Retained Earnings | | 2,020.0 | | | 1,811.9 | | Retained Earnings | | 2,253.6 | | | 2,050.9 | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) | | 1.8 | | | 1.9 | | Accumulated Other Comprehensive Income (Loss) | | 5.5 | | | 6.7 | |
TOTAL COMMON SHAREHOLDER’S EQUITY | TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,114.1 | | | 2,626.1 | | TOTAL COMMON SHAREHOLDER’S EQUITY | | 3,704.7 | | | 3,149.9 | |
| Noncontrolling Interest | Noncontrolling Interest | | 0.4 | | | 1.6 | | Noncontrolling Interest | | 0.4 | | | (0.1) | |
| TOTAL EQUITY | TOTAL EQUITY | | 3,114.5 | | | 2,627.7 | | TOTAL EQUITY | | 3,705.1 | | | 3,149.8 | |
| TOTAL LIABILITIES AND EQUITY | TOTAL LIABILITIES AND EQUITY | | $ | 9,172.5 | | | $ | 8,154.1 | | TOTAL LIABILITIES AND EQUITY | | $ | 10,293.1 | | | $ | 9,325.7 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 20212022 and 20202021
(in millions)
(Unaudited)
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | | 2022 | | 2021 |
OPERATING ACTIVITIES | OPERATING ACTIVITIES | | | | | OPERATING ACTIVITIES | | | | |
Net Income | Net Income | | $ | 210.7 | | | $ | 163.9 | | Net Income | | $ | 263.3 | | | $ | 210.7 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | |
Depreciation and Amortization | Depreciation and Amortization | | 217.4 | | | 203.9 | | Depreciation and Amortization | | 251.8 | | | 217.4 | |
Deferred Income Taxes | Deferred Income Taxes | | 22.5 | | | (0.3) | | Deferred Income Taxes | | 7.5 | | | 22.5 | |
| Allowance for Equity Funds Used During Construction | Allowance for Equity Funds Used During Construction | | (5.4) | | | (5.7) | | Allowance for Equity Funds Used During Construction | | (3.4) | | | (5.4) | |
Mark-to-Market of Risk Management Contracts | Mark-to-Market of Risk Management Contracts | | (18.1) | | | (2.3) | | Mark-to-Market of Risk Management Contracts | | (27.6) | | | (18.1) | |
Pension Contributions to Qualified Plan Trust | | — | | | (8.9) | | |
| Property Taxes | Property Taxes | | (20.0) | | | (16.5) | | Property Taxes | | (22.0) | | | (20.0) | |
Deferred Fuel Over/Under-Recovery, Net | Deferred Fuel Over/Under-Recovery, Net | | (506.8) | | | 16.3 | | Deferred Fuel Over/Under-Recovery, Net | | (82.0) | | | (506.8) | |
Change in Regulatory Assets | Change in Regulatory Assets | | (91.5) | | | (64.5) | | Change in Regulatory Assets | | 3.1 | | | (91.5) | |
Change in Other Noncurrent Assets | Change in Other Noncurrent Assets | | 38.3 | | | 3.2 | | Change in Other Noncurrent Assets | | 52.0 | | | 38.3 | |
Change in Other Noncurrent Liabilities | Change in Other Noncurrent Liabilities | | 40.0 | | | 21.0 | | Change in Other Noncurrent Liabilities | | 17.3 | | | 40.0 | |
Changes in Certain Components of Working Capital: | Changes in Certain Components of Working Capital: | | | | | Changes in Certain Components of Working Capital: | | | | |
Accounts Receivable, Net | Accounts Receivable, Net | | (70.2) | | | 8.0 | | Accounts Receivable, Net | | (17.9) | | | (70.2) | |
Fuel, Materials and Supplies | Fuel, Materials and Supplies | | 115.1 | | | (70.9) | | Fuel, Materials and Supplies | | 23.5 | | | 115.1 | |
Accounts Payable | Accounts Payable | | (21.1) | | | 88.0 | | Accounts Payable | | 78.9 | | | (21.1) | |
Accrued Taxes, Net | Accrued Taxes, Net | | 72.2 | | | 46.6 | | Accrued Taxes, Net | | (1.1) | | | 72.2 | |
| Other Current Assets | Other Current Assets | | 4.2 | | | 1.3 | | Other Current Assets | | (12.0) | | | 4.2 | |
Other Current Liabilities | Other Current Liabilities | | (48.2) | | | (50.3) | | Other Current Liabilities | | (38.1) | | | (48.2) | |
Net Cash Flows from (Used for) Operating Activities | Net Cash Flows from (Used for) Operating Activities | | (60.9) | | | 332.8 | | Net Cash Flows from (Used for) Operating Activities | | 493.3 | | | (60.9) | |
| INVESTING ACTIVITIES | INVESTING ACTIVITIES | | | | | INVESTING ACTIVITIES | | | | |
Construction Expenditures | Construction Expenditures | | (277.2) | | | (319.5) | | Construction Expenditures | | (397.0) | | | (277.2) | |
| Change in Advances to Affiliates, Net | | Change in Advances to Affiliates, Net | | 153.8 | | | — | |
Acquisition of the North Central Wind Energy Facilities | Acquisition of the North Central Wind Energy Facilities | | (355.8) | | | — | | Acquisition of the North Central Wind Energy Facilities | | (658.0) | | | (355.8) | |
Other Investing Activities | Other Investing Activities | | 2.1 | | | 4.8 | | Other Investing Activities | | 3.9 | | | 2.1 | |
Net Cash Flows Used for Investing Activities | Net Cash Flows Used for Investing Activities | | (630.9) | | | (314.7) | | Net Cash Flows Used for Investing Activities | | (897.3) | | | (630.9) | |
| FINANCING ACTIVITIES | FINANCING ACTIVITIES | | | | | FINANCING ACTIVITIES | | | | |
Capital Contribution from Parent | Capital Contribution from Parent | | 280.0 | | | — | | Capital Contribution from Parent | | 353.3 | | | 280.0 | |
Issuance of Long-term Debt – Nonaffiliated | Issuance of Long-term Debt – Nonaffiliated | | 496.4 | | | — | | Issuance of Long-term Debt – Nonaffiliated | | — | | | 496.4 | |
| Change in Short-term Debt – Nonaffiliated | Change in Short-term Debt – Nonaffiliated | | (35.0) | | | 23.7 | | Change in Short-term Debt – Nonaffiliated | | — | | | (35.0) | |
Change in Advances from Affiliates, Net | Change in Advances from Affiliates, Net | | (1.7) | | | 11.9 | | Change in Advances from Affiliates, Net | | 156.3 | | | (1.7) | |
Retirement of Long-term Debt – Nonaffiliated | Retirement of Long-term Debt – Nonaffiliated | | (4.7) | | | (19.7) | | Retirement of Long-term Debt – Nonaffiliated | | (4.7) | | | (4.7) | |
Principal Payments for Finance Lease Obligations | Principal Payments for Finance Lease Obligations | | (8.1) | | | (8.0) | | Principal Payments for Finance Lease Obligations | | (8.0) | | | (8.1) | |
| Dividends Paid on Common Stock | | Dividends Paid on Common Stock | | (57.5) | | | — | |
Dividends Paid on Common Stock – Nonaffiliated | Dividends Paid on Common Stock – Nonaffiliated | | (3.8) | | | (2.3) | | Dividends Paid on Common Stock – Nonaffiliated | | (2.6) | | | (3.8) | |
Other Financing Activities | Other Financing Activities | | 0.5 | | | 0.3 | | Other Financing Activities | | 0.4 | | | 0.5 | |
Net Cash Flows from Financing Activities | Net Cash Flows from Financing Activities | | 723.6 | | | 5.9 | | Net Cash Flows from Financing Activities | | 437.2 | | | 723.6 | |
| Net Increase in Cash and Cash Equivalents | Net Increase in Cash and Cash Equivalents | | 31.8 | | | 24.0 | | Net Increase in Cash and Cash Equivalents | | 33.2 | | | 31.8 | |
Cash and Cash Equivalents at Beginning of Period | Cash and Cash Equivalents at Beginning of Period | | 13.2 | | | 1.6 | | Cash and Cash Equivalents at Beginning of Period | | 51.2 | | | 13.2 | |
Cash and Cash Equivalents at End of Period | Cash and Cash Equivalents at End of Period | | $ | 45.0 | | | $ | 25.6 | | Cash and Cash Equivalents at End of Period | | $ | 84.4 | | | $ | 45.0 | |
| SUPPLEMENTARY INFORMATION | SUPPLEMENTARY INFORMATION | | | | | SUPPLEMENTARY INFORMATION | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 98.0 | | | $ | 95.2 | | Cash Paid for Interest, Net of Capitalized Amounts | | $ | 102.1 | | | $ | 98.0 | |
Net Cash Paid (Received) for Income Taxes | Net Cash Paid (Received) for Income Taxes | | (11.3) | | | 11.9 | | Net Cash Paid (Received) for Income Taxes | | 34.7 | | | (11.3) | |
Noncash Acquisitions Under Finance Leases | Noncash Acquisitions Under Finance Leases | | 4.4 | | | 5.9 | | Noncash Acquisitions Under Finance Leases | | 3.2 | | | 4.4 | |
Construction Expenditures Included in Current Liabilities as of September 30, | Construction Expenditures Included in Current Liabilities as of September 30, | | 46.8 | | | 50.6 | | Construction Expenditures Included in Current Liabilities as of September 30, | | 71.8 | | | 46.8 | |
| See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 138. | |
See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. | | See Condensed Notes to Condensed Financial Statements of Registrants beginning on page 144. |
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 | | |
New Accounting Standards | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Comprehensive Income | | AEP, AEP Texas, APCo, I&M, PSO, SWEPCo | | |
Rate Matters | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Commitments, Guarantees and Contingencies | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Acquisitions, Assets and Liabilities Held for Sale, Dispositions and Impairments | | AEP, AEPTCo, PSO, SWEPCo | | |
Benefit Plans | | AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo | | |
Business Segments | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Derivatives and Hedging | | AEP, AEP Texas, APCo, I&M, OPCo, PSO, SWEPCo | | |
Fair Value Measurements | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Income Taxes | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Financing Activities | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
| | | | |
Property, Plant and Equipment | | AEP, APCoPSO, SWEPCo | | |
Revenue from Contracts with Customers | | AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO, SWEPCo | | |
Subsequent Events | | AEP, AEPTCo | | |
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 nine months ended September 30, 20212022 is not necessarily indicative of results that may be expected for the year ending December 31, 2021.2022. The condensed financial statements are unaudited and should be read in conjunction with the audited 20202021 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, 2021.24, 2022.
AEP System Tax Allocation
The Registrant Subsidiaries join in the filing of a consolidated tax return. Historically, the allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocated the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries through a reduction of current tax expense. In the first quarter of 2022, AEP and subsidiaries changed accounting for the Parent Company Loss Benefit from a reduction of current tax expense to an allocation through equity. The impact of this change was immaterial to the Registrant Subsidiaries’ financial statements.
Deferred Fuel Costs (Applies to all Registrants except AEP Texas, AEPTCo and OPCo)
The cost of purchased electricity, fuel and related emission allowances and emission control chemicals/consumables is charged to Purchased Electricity, Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily using the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is an expectation that refunds or recoveries will extend beyond a one year period, based on a company’s filing with a commission or a commission directive. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. The Registrants share the majority of their Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
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 September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (in millions, except per share data) | | (in millions, except per share data) |
| | | | $/share | | $/share | | | | $/share | | $/share |
| Earnings Attributable to AEP Common Shareholders | Earnings Attributable to AEP Common Shareholders | $ | 796.0 | | | | | $ | 748.6 | | | | Earnings Attributable to AEP Common Shareholders | $ | 683.7 | | | | | $ | 796.0 | | | |
| Weighted-Average Number of Basic AEP Common Shares Outstanding | Weighted-Average Number of Basic AEP Common Shares Outstanding | 501.2 | | | $ | 1.59 | | | 496.2 | | | $ | 1.51 | | Weighted-Average Number of Basic AEP Common Shares Outstanding | 513.7 | | | $ | 1.33 | | | 501.2 | | | $ | 1.59 | |
Weighted-Average Dilutive Effect of Stock-Based Awards | Weighted-Average Dilutive Effect of Stock-Based Awards | 1.4 | | | (0.01) | | | 1.3 | | | (0.01) | | Weighted-Average Dilutive Effect of Stock-Based Awards | 1.6 | | | — | | | 1.4 | | | (0.01) | |
Weighted-Average Number of Diluted AEP Common Shares Outstanding | Weighted-Average Number of Diluted AEP Common Shares Outstanding | 502.6 | | | $ | 1.58 | | | 497.5 | | | $ | 1.50 | | Weighted-Average Number of Diluted AEP Common Shares Outstanding | 515.3 | | | $ | 1.33 | | | 502.6 | | | $ | 1.58 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
| (in millions, except per share data) |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 1,949.2 | | | | | $ | 1,764.6 | | | |
| | | | | | | |
Weighted-Average Number of Basic AEP Common Shares Outstanding | 499.4 | | | $ | 3.90 | | | 495.5 | | | $ | 3.56 | |
Weighted-Average Dilutive Effect of Stock-Based Awards | 1.2 | | | (0.01) | | | 1.4 | | | (0.01) | |
Weighted-Average Number of Diluted AEP Common Shares Outstanding | 500.6 | | | $ | 3.89 | | | 496.9 | | | $ | 3.55 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2022 | | 2021 |
| (in millions, except per share data) |
| | | $/share | | | | $/share |
| | | | | | | |
| | | | | | | |
Earnings Attributable to AEP Common Shareholders | $ | 1,922.9 | | | | | $ | 1,949.2 | | | |
| | | | | | | |
Weighted-Average Number of Basic AEP Common Shares Outstanding | 511.2 | | | $ | 3.76 | | | 499.4 | | | $ | 3.90 | |
Weighted-Average Dilutive Effect of Stock-Based Awards | 1.5 | | | (0.01) | | | 1.2 | | | (0.01) | |
Weighted-Average Number of Diluted AEP Common Shares Outstanding | 512.7 | | | $ | 3.75 | | | 500.6 | | | $ | 3.89 | |
Equity Units are potentially dilutive securities butand were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 20212022 and 2020,2021, as the dilutive stock price thresholds werethreshold was not met. See Note 12 - Financing Activities for more information related to Equity Units.
There were 0 and 377 thousand antidilutive shares outstanding as of September 30, 2022 and 2021, respectively.
There were 377 thousand and 0 antidilutive shares outstanding as of September 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:
| | | September 30, 2021 | | September 30, 2022 |
| | AEP | | AEP Texas | | APCo | | AEP | | AEP Texas | | APCo |
| | (in millions) | | (in millions) |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 1,372.7 | | | $ | 0.1 | | | $ | 5.0 | | Cash and Cash Equivalents | | $ | 522.2 | | | $ | 0.1 | | | $ | 6.7 | |
Restricted Cash | Restricted Cash | | 54.0 | | | 43.9 | | | 10.1 | | Restricted Cash | | 55.1 | | | 47.7 | | | 7.4 | |
Total Cash, Cash Equivalents and Restricted Cash | Total Cash, Cash Equivalents and Restricted Cash | | $ | 1,426.7 | | | $ | 44.0 | | | $ | 15.1 | | Total Cash, Cash Equivalents and Restricted Cash | | $ | 577.3 | | | $ | 47.8 | | | $ | 14.1 | |
| | | December 31, 2020 | | December 31, 2021 |
| | AEP | | AEP Texas | | APCo | | AEP | | AEP Texas | | APCo |
| | (in millions) | | (in millions) |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 392.7 | | | $ | 0.1 | | | $ | 5.8 | | Cash and Cash Equivalents | | $ | 403.4 | | | $ | 0.1 | | | $ | 2.5 | |
Restricted Cash | Restricted Cash | | 45.6 | | | 28.7 | | | 16.9 | | Restricted Cash | | 48.0 | | | 30.4 | | | 17.6 | |
Total Cash, Cash Equivalents and Restricted Cash | Total Cash, Cash Equivalents and Restricted Cash | | $ | 438.3 | | | $ | 28.8 | | | $ | 22.7 | | Total Cash, Cash Equivalents and Restricted Cash | | $ | 451.4 | | | $ | 30.5 | | | $ | 20.1 | |
Supplementary Cash Flow Information (Applies to AEP)
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
Cash Flow Information | | 2022 | | 2021 |
| | (in millions) |
Cash Paid for: | | | | |
Interest, Net of Capitalized Amounts | | $ | 856.8 | | | $ | 775.2 | |
Income Taxes | | 104.1 | | | 9.3 | |
Noncash Investing and Financing Activities: | | | | |
Acquisitions Under Finance Leases | | 22.3 | | | 23.0 | |
Construction Expenditures Included in Current Liabilities as of September 30, | | 985.8 | | | 764.1 | |
| | | | |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | | 8.5 | | | 0.3 | |
| | | | |
Noncash Contribution of Assets to Cedar Creek Project | | — | | | (9.3) | |
Noncontrolling Interest Assumed - Dry Lake Solar Project | | — | | | 35.0 | |
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.
3. COMPREHENSIVE INCOME
The disclosures in this note apply to all Registrants except AEPTCo and OPCo unless indicated otherwise.OPCo.
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 September 30, 2022 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2022 | | $ | 533.6 | | | $ | (10.8) | | | $ | 28.6 | | | $ | 551.4 | |
Change in Fair Value Recognized in AOCI | | 94.3 | | | 7.4 | | (a) | — | | | 101.7 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.2 | | | — | | | — | | | 0.2 | |
Purchased Electricity for Resale (b) | | (222.6) | | | — | | | — | | | (222.6) | |
Interest Expense (b) | | — | | | 0.9 | | | — | | | 0.9 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (6.2) | | | (6.2) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.2 | | | 2.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (222.4) | | | 0.9 | | | (4.0) | | | (225.5) | |
Income Tax (Expense) Benefit | | (46.6) | | | 0.1 | | | (0.8) | | | (47.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (175.8) | | | 0.8 | | | (3.2) | | | (178.2) | |
Net Current Period Other Comprehensive Income (Loss) | | (81.5) | | | 8.2 | | | (3.2) | | | (76.5) | |
Balance in AOCI as of September 30, 2022 | | $ | 452.1 | | | $ | (2.6) | | | $ | 25.4 | | | $ | 474.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Three Months Ended September 30, 2021 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2021 | | $ | 110.3 | | | $ | (32.2) | | | $ | 18.9 | | | $ | 97.0 | |
Change in Fair Value Recognized in AOCI | | 220.8 | | | 4.9 | | (a) | — | | | 225.7 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
Purchased Electricity for Resale (b) | | (59.7) | | | — | | | — | | | (59.7) | |
Interest Expense (b) | | — | | | 1.5 | | | — | | | 1.5 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (4.8) | | | (4.8) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.3 | | | 2.3 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (59.7) | | | 1.5 | | | (2.5) | | | (60.7) | |
Income Tax (Expense) Benefit | | (12.5) | | | 0.3 | | | (0.5) | | | (12.7) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (47.2) | | | 1.2 | | | (2.0) | | | (48.0) | |
Net Current Period Other Comprehensive Income (Loss) | | 173.6 | | | 6.1 | | | (2.0) | | | 177.7 | |
Balance in AOCI as of September 30, 2021 | | $ | 283.9 | | | $ | (26.1) | | | $ | 16.9 | | | $ | 274.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Three Months Ended September 30, 2020 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of June 30, 2020 | | $ | (81.4) | | | $ | (55.3) | | | $ | (36.2) | | | $ | (172.9) | |
Change in Fair Value Recognized in AOCI | | 10.2 | | | 1.9 | | (a) | — | | | 12.1 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.1) | | | — | | | — | | | (0.1) | |
Purchased Electricity for Resale (b) | | 33.3 | | | — | | | — | | | 33.3 | |
Interest Expense (b) | | — | | | 1.3 | | | — | | | 1.3 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (4.9) | | | (4.9) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 2.6 | | | 2.6 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 33.2 | | | 1.3 | | | (2.3) | | | 32.2 | |
Income Tax (Expense) Benefit | | 7.1 | | | 0.2 | | | (0.5) | | | 6.8 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 26.1 | | | 1.1 | | | (1.8) | | | 25.4 | |
Net Current Period Other Comprehensive Income (Loss) | | 36.3 | | | 3.0 | | | (1.8) | | | 37.5 | |
Balance in AOCI as of September 30, 2020 | | $ | (45.1) | | | $ | (52.3) | | | $ | (38.0) | | | $ | (135.4) | |
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 30, 2022 | | Commodity | | Interest Rate | | and OPEB | | Total |
| | (in millions) |
Balance in AOCI as of December 31, 2021 | | $ | 163.7 | | | $ | (21.3) | | | $ | 42.4 | | | $ | 184.8 | |
Change in Fair Value Recognized in AOCI | | 629.8 | | | 16.2 | | (a) | — | | | 646.0 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.2 | | | — | | | — | | | 0.2 | |
Purchased Electricity for Resale (b) | | (432.3) | | | — | | | — | | | (432.3) | |
Interest Expense (b) | | — | | | 3.1 | | | — | | | 3.1 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (16.5) | | | (16.5) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 6.4 | | | 6.4 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (432.1) | | | 3.1 | | | (10.1) | | | (439.1) | |
Income Tax (Expense) Benefit | | (90.7) | | | 0.6 | | | (2.1) | | | (92.2) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (341.4) | | | 2.5 | | | (8.0) | | | (346.9) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI | | — | | | — | | | (11.4) | | | (11.4) | |
Income Tax (Expense) Benefit | | — | | | — | | | (2.4) | | | (2.4) | |
Reclassifications of KPCo Pension and OPEB Regulatory Assets to AOCI, Net of Income Tax (Expense) Benefit | | — | | | — | | | (9.0) | | | (9.0) | |
Net Current Period Other Comprehensive Income (Loss) | | 288.4 | | | 18.7 | | | (17.0) | | | 290.1 | |
Balance in AOCI as of September 30, 2022 | | $ | 452.1 | | | $ | (2.6) | | | $ | 25.4 | | | $ | 474.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 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 | | 534.5 | | | 17.6 | | (a) | — | | | 552.1 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.7 | | | — | | | — | | | 0.7 | |
Purchased Electricity for Resale (b) | | (241.2) | | | — | | | — | | | (241.2) | |
Interest Expense (b) | | — | | | 4.8 | | | — | | | 4.8 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (14.5) | | | (14.5) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 6.8 | | | 6.8 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (240.5) | | | 4.8 | | | (7.7) | | | (243.4) | |
Income Tax (Expense) Benefit | | (50.5) | | | 1.0 | | | (1.6) | | | (51.1) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (190.0) | | | 3.8 | | | (6.1) | | | (192.3) | |
Net Current Period Other Comprehensive Income (Loss) | | 344.5 | | | 21.4 | | | (6.1) | | | 359.8 | |
Balance in AOCI as of September 30, 2021 | | $ | 283.9 | | | $ | (26.1) | | | $ | 16.9 | | | $ | 274.7 | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2022 | | | | $ | (0.8) | | | $ | (5.2) | | | $ | (6.0) | |
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 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 | | | | 0.3 | | | — | | | 0.3 | |
Income Tax (Expense) Benefit | | | | 0.1 | | | — | | | 0.1 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.3 | | | — | | | 0.3 | |
Balance in AOCI as of September 30, 2022 | | | | $ | (0.5) | | | $ | (5.2) | | | $ | (5.7) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | (1.8) | | | $ | (6.5) | | | $ | (8.3) | |
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) | | | | — | | | (0.1) | | | (0.1) | |
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 September 30, 2021 | | | | $ | (1.5) | | | $ | (6.5) | | | $ | (8.0) | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2021 | | | | $ | (1.3) | | | $ | (5.2) | | | $ | (6.5) | |
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) | | | | — | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
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 September 30, 2022 | | | | $ | (0.5) | | | $ | (5.2) | | | $ | (5.7) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.0 | | | — | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.0 | | | 0.1 | | | 1.1 | |
Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | 0.1 | | | 0.9 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.8 | | | 0.1 | | | 0.9 | |
Balance in AOCI as of September 30, 2021 | | | | $ | (1.5) | | | $ | (6.5) | | | $ | (8.0) | |
APCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2022 | | | | $ | 7.1 | | | $ | 14.8 | | | $ | 21.9 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.3) | | | — | | | (0.3) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.4) | | | (1.4) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.3) | | | (1.4) | | | (1.7) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.3) | | | (0.4) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.2) | | | (1.1) | | | (1.3) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.2) | | | (1.1) | | | (1.3) | |
Balance in AOCI as of September 30, 2022 | | | | $ | 6.9 | | | $ | 13.7 | | | $ | 20.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | 8.0 | | | $ | 5.9 | | | $ | 13.9 | |
Change in Fair Value Recognized in AOCI | | | | 0.2 | | | — | | | 0.2 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.6) | | | — | | | (0.6) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.2) | | | (1.2) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.6) | | | (1.2) | | | (1.8) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.2) | | | (0.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.5) | | | (1.0) | | | (1.5) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.3) | | | (1.0) | | | (1.3) | |
Balance in AOCI as of September 30, 2021 | | | | $ | 7.7 | | | $ | 4.9 | | | $ | 12.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
APCo | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2021 | | | | $ | 7.5 | | | $ | 16.9 | | | $ | 24.4 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.8) | | | — | | | (0.8) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (4.1) | | | (4.1) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.8) | | | (4.1) | | | (4.9) | |
Income Tax (Expense) Benefit | | | | (0.2) | | | (0.9) | | | (1.1) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.6) | | | (3.2) | | | (3.8) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.6) | | | (3.2) | | | (3.8) | |
Balance in AOCI as of September 30, 2022 | | | | $ | 6.9 | | | $ | 13.7 | | | $ | 20.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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 | | | | 9.3 | | | — | | | 9.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (1.0) | | | — | | | (1.0) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (3.9) | | | (3.9) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (1.0) | | | (3.9) | | | (4.9) | |
Income Tax (Expense) Benefit | | | | (0.2) | | | (0.8) | | | (1.0) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.8) | | | (3.1) | | | (3.9) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 8.5 | | | (3.1) | | | 5.4 | |
Balance in AOCI as of September 30, 2021 | | | | $ | 7.7 | | | $ | 4.9 | | | $ | 12.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2022 | | | | $ | (5.9) | | | $ | 5.2 | | | $ | (0.7) | |
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) | | | | — | | | (0.3) | | | (0.3) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.5 | | | (0.2) | | | 0.3 | |
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 September 30, 2022 | | | | $ | (5.5) | | | $ | 5.1 | | | $ | (0.4) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | (7.4) | | | $ | 1.2 | | | $ | (6.2) | |
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) | | | | — | | | (0.2) | | | (0.2) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
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 September 30, 2021 | | | | $ | (7.0) | | | $ | 1.2 | | | $ | (5.8) | |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2021 | | | | $ | (6.7) | | | $ | 5.4 | | | $ | (1.3) | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | 1.5 | | | — | | | 1.5 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.7) | | | (0.7) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.3 | | | 0.3 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.5 | | | (0.4) | | | 1.1 | |
Income Tax (Expense) Benefit | | | | 0.3 | | | (0.1) | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.2 | | | (0.3) | | | 0.9 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.2 | | | (0.3) | | | 0.9 | |
Balance in AOCI as of September 30, 2022 | | | | $ | (5.5) | | | $ | 5.1 | | | $ | (0.4) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.6 | | | — | | | 1.6 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.6) | | | (0.6) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.5 | | | 0.5 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.6 | | | (0.1) | | | 1.5 | |
Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.3 | | | (0.1) | | | 1.2 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.3 | | | (0.1) | | | 1.2 | |
Balance in AOCI as of September 30, 2021 | | | | $ | (7.0) | | | $ | 1.2 | | | $ | (5.8) | |
| | | | | | | | | | | | | | |
PSO | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended September 30, 2022 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of June 30, 2022 | | | | $ | — | | | | | |
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 September 30, 2022 | | | | $ | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
—
AEP | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 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 | | 534.5 | | | 17.6 | | (a) | — | | | 552.1 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | 0.7 | | | — | | | — | | | 0.7 | |
Purchased Electricity for Resale (b) | | (241.2) | | | — | | | — | | | (241.2) | |
Interest Expense (b) | | — | | | 4.8 | | | — | | | 4.8 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (14.5) | | | (14.5) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 6.8 | | | 6.8 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | (240.5) | | | 4.8 | | | (7.7) | | | (243.4) | |
Income Tax (Expense) Benefit | | (50.5) | | | 1.0 | | | (1.6) | | | (51.1) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | (190.0) | | | 3.8 | | | (6.1) | | | (192.3) | |
Net Current Period Other Comprehensive Income (Loss) | | 344.5 | | | 21.4 | | | (6.1) | | | 359.8 | |
Balance in AOCI as of September 30, 2021 | | $ | 283.9 | | | $ | (26.1) | | | $ | 16.9 | | | $ | 274.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Pension | | |
Nine Months Ended September 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 | | (48.6) | | | (43.6) | | (a) | — | | | (92.2) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
Generation & Marketing Revenues (b) | | (0.3) | | | — | | | — | | | (0.3) | |
Purchased Electricity for Resale (b) | | 135.7 | | | — | | | — | | | 135.7 | |
Interest Expense (b) | | — | | | 3.6 | | | — | | | 3.6 | |
Amortization of Prior Service Cost (Credit) | | — | | | — | | | (14.4) | | | (14.4) | |
Amortization of Actuarial (Gains) Losses | | — | | | — | | | 7.7 | | | 7.7 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | 135.4 | | | 3.6 | | | (6.7) | | | 132.3 | |
Income Tax (Expense) Benefit | | 28.4 | | | 0.8 | | | (1.4) | | | 27.8 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | 107.0 | | | 2.8 | | | (5.3) | | | 104.5 | |
Net Current Period Other Comprehensive Income (Loss) | | 58.4 | | | (40.8) | | | (5.3) | | | 12.3 | |
Balance in AOCI as of September 30, 2020 | | $ | (45.1) | | | $ | (52.3) | | | $ | (38.0) | | | $ | (135.4) | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | (1.8) | | | $ | (6.5) | | | $ | (8.3) | |
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) | | | | — | | | (0.1) | | | (0.1) | |
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 September 30, 2021 | | | | $ | (1.5) | | | $ | (6.5) | | | $ | (8.0) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2020 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2020 | | | | $ | (2.9) | | | $ | (9.3) | | | $ | (12.2) | |
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) | | | | — | | | (0.1) | | | (0.1) | |
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 September 30, 2020 | | | | $ | (2.6) | | | $ | (9.3) | | | $ | (11.9) | |
AEP Texas
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.0 | | | — | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.0 | | | 0.1 | | | 1.1 | |
Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | 0.1 | | | 0.9 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.8 | | | 0.1 | | | 0.9 | |
Balance in AOCI as of September 30, 2021 | | | | $ | (1.5) | | | $ | (6.5) | | | $ | (8.0) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.0 | | | — | | | 1.0 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.1) | | | (0.1) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.0 | | | 0.1 | | | 1.1 | |
Income Tax (Expense) Benefit | | | | 0.2 | | | — | | | 0.2 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.8 | | | 0.1 | | | 0.9 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.8 | | | 0.1 | | | 0.9 | |
Balance in AOCI as of September 30, 2020 | | | | $ | (2.6) | | | $ | (9.3) | | | $ | (11.9) | |
APCo
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | 8.0 | | | $ | 5.9 | | | $ | 13.9 | |
Change in Fair Value Recognized in AOCI | | | | 0.2 | | | — | | | 0.2 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.6) | | | — | | | (0.6) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.2) | | | (1.2) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.6) | | | (1.2) | | | (1.8) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.2) | | | (0.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.5) | | | (1.0) | | | (1.5) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.3) | | | (1.0) | | | (1.3) | |
Balance in AOCI as of September 30, 2021 | | | | $ | 7.7 | | | $ | 4.9 | | | $ | 12.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2020 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2020 | | | | $ | (4.1) | | | $ | 2.2 | | | $ | (1.9) | |
Change in Fair Value Recognized in AOCI | | | | 0.7 | | | — | | | 0.7 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.2) | | | — | | | (0.2) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.3) | | | (1.3) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.1 | | | 0.1 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.2) | | | (1.2) | | | (1.4) | |
Income Tax (Expense) Benefit | | | | (0.1) | | | (0.3) | | | (0.4) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.1) | | | (0.9) | | | (1.0) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.6 | | | (0.9) | | | (0.3) | |
Balance in AOCI as of September 30, 2020 | | | | $ | (3.5) | | | $ | 1.3 | | | $ | (2.2) | |
| | | | | | | | | | | | | | | | | | | | | | |
APCo | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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 | | | | 9.3 | | | — | | | 9.3 | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (1.0) | | | — | | | (1.0) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (3.9) | | | (3.9) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (1.0) | | | (3.9) | | | (4.9) | |
Income Tax (Expense) Benefit | | | | (0.2) | | | (0.8) | | | (1.0) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.8) | | | (3.1) | | | (3.9) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 8.5 | | | (3.1) | | | 5.4 | |
Balance in AOCI as of September 30, 2021 | | | | $ | 7.7 | | | $ | 4.9 | | | $ | 12.6 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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 | | | | (3.8) | | | — | | | (3.8) | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.8) | | | — | | | (0.8) | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (4.0) | | | (4.0) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.4 | | | 0.4 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.8) | | | (3.6) | | | (4.4) | |
Income Tax (Expense) Benefit | | | | (0.2) | | | (0.8) | | | (1.0) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.6) | | | (2.8) | | | (3.4) | |
Net Current Period Other Comprehensive Income (Loss) | | | | (4.4) | | | (2.8) | | | (7.2) | |
Balance in AOCI as of September 30, 2020 | | | | $ | (3.5) | | | $ | 1.3 | | | $ | (2.2) | |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | (7.4) | | | $ | 1.2 | | | $ | (6.2) | |
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) | | | | — | | | (0.2) | | | (0.2) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
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 September 30, 2021 | | | | $ | (7.0) | | | $ | 1.2 | | | $ | (5.8) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2020 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2020 | | | | $ | (9.1) | | | $ | (1.7) | | | $ | (10.8) | |
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) | | | | — | | | (0.3) | | | (0.3) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.2 | | | 0.2 | |
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 September 30, 2020 | | | | $ | (8.7) | | | $ | (1.8) | | | $ | (10.5) | |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.6 | | | — | | | 1.6 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.6) | | | (0.6) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.5 | | | 0.5 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.6 | | | (0.1) | | | 1.5 | |
Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.3 | | | (0.1) | | | 1.2 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.3 | | | (0.1) | | | 1.2 | |
Balance in AOCI as of September 30, 2021 | | | | $ | (7.0) | | | $ | 1.2 | | | $ | (5.8) | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.5 | | | — | | | 1.5 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (0.6) | | | (0.6) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | 0.5 | | | 0.5 | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.5 | | | (0.1) | | | 1.4 | |
Income Tax (Expense) Benefit | | | | 0.3 | | | — | | | 0.3 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.2 | | | (0.1) | | | 1.1 | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.2 | | | (0.1) | | | 1.1 | |
Balance in AOCI as of September 30, 2020 | | | | $ | (8.7) | | | $ | (1.8) | | | $ | (10.5) | |
| | | | | | | | | | | | | | |
PSO | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of June 30, 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 September 30, 2021 | | | | $ | — | | | | | |
| | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
ThreeNine Months Ended September 30, 20202022 | | | | Interest Rate | | | | |
| | | (in millions) |
Balance in AOCI as of June 30, 2020December 31, 2021 | | | | $ | 0.6— | | | | | |
Change in Fair Value Recognized in AOCI | | | | — | | | | | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Interest Expense (b) | | | | (0.3)— | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (0.3)— | | | | | |
Income Tax (Expense) Benefit | | | | — | | | | | |
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 September 30, 20202022 | | | | $ | 0.3— | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Nine Months Ended September 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 September 30, 2021 | | | | $ | — | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | | | |
Nine Months Ended September 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) | | | | (1.0) | | | | | |
| | | | | | | | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | (1.0) | | | | | |
Income Tax (Expense) Benefit | | | | (0.2) | | | | | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | (0.8) | | | | | |
Net Current Period Other Comprehensive Income (Loss) | | | | (0.8) | | | | | |
Balance in AOCI as of September 30, 2020 | | | | $ | 0.3 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2021 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2021 | | | | $ | 0.5 | | | $ | 1.4 | | | $ | 1.9 | |
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) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 0.4 | | | (0.5) | | | (0.1) | |
Income Tax (Expense) Benefit | | | | 0.1 | | | (0.1) | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 0.3 | | | (0.4) | | | (0.1) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 0.3 | | | (0.4) | | | (0.1) | |
Balance in AOCI as of September 30, 2021 | | | | $ | 0.8 | | | $ | 1.0 | | | $ | 1.8 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Three Months Ended September 30, 2020 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of June 30, 2020 | | | | $ | (1.1) | | | $ | (0.2) | | | $ | (1.3) | |
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) | |
Amortization of Actuarial (Gains) Losses | | | | — | | | — | | | — | |
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 September 30, 2020 | | | | $ | (0.7) | | | $ | (0.6) | | | $ | (1.3) | |
| SWEPCo | SWEPCo | | | SWEPCo | | |
| | | | | | | Cash Flow Hedge – | | Pension | |
Three Months Ended September 30, 2022 | | Three Months Ended September 30, 2022 | | | Interest Rate | | and OPEB | | Total |
| | | | Cash Flow Hedge – | | Pension | | | | (in millions) |
Nine Months Ended September 30, 2021 | | | Interest Rate | | and OPEB | | Total | |
| | (in millions) | |
Balance in AOCI as of December 31, 2020 | | | $ | (0.3) | | | $ | 2.2 | | | $ | 1.9 | | |
Balance in AOCI as of June 30, 2022 | | Balance in AOCI as of June 30, 2022 | | | $ | 1.2 | | | $ | 4.7 | | | $ | 5.9 | |
Change in Fair Value Recognized in AOCI | Change in Fair Value Recognized in AOCI | | | — | | | — | | | — | | Change in Fair Value Recognized in AOCI | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | Amount of (Gain) Loss Reclassified from AOCI | | | Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense (b) | | | 1.4 | | | — | | | 1.4 | | |
| Amortization of Prior Service Cost (Credit) | Amortization of Prior Service Cost (Credit) | | | — | | | (1.5) | | | (1.5) | | Amortization of Prior Service Cost (Credit) | | | — | | | (0.5) | | | (0.5) | |
| Reclassifications from AOCI, before Income Tax (Expense) Benefit | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 1.4 | | | (1.5) | | | (0.1) | | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | — | | | (0.5) | | | (0.5) | |
Income Tax (Expense) Benefit | Income Tax (Expense) Benefit | | | 0.3 | | | (0.3) | | | — | | Income Tax (Expense) Benefit | | | — | | | (0.1) | | | (0.1) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 1.1 | | | (1.2) | | | (0.1) | | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | — | | | (0.4) | | | (0.4) | |
Net Current Period Other Comprehensive Income (Loss) | Net Current Period Other Comprehensive Income (Loss) | | | 1.1 | | | (1.2) | | | (0.1) | | Net Current Period Other Comprehensive Income (Loss) | | | — | | | (0.4) | | | (0.4) | |
Balance in AOCI as of September 30, 2021 | | | $ | 0.8 | | | $ | 1.0 | | | $ | 1.8 | | |
Balance in AOCI as of September 30, 2022 | | Balance in AOCI as of September 30, 2022 | | | $ | 1.2 | | | $ | 4.3 | | | $ | 5.5 | |
| | | | | | | | Cash Flow Hedge – | | Pension | |
Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2021 | | | Interest Rate | | and OPEB | | Total |
| | | | Cash Flow Hedge – | | Pension | | | | (in millions) |
Nine Months Ended September 30, 2020 | | | Interest Rate | | and OPEB | | Total | |
| | (in millions) | |
Balance in AOCI as of December 31, 2019 | | | $ | (1.8) | | | $ | 0.5 | | | $ | (1.3) | | |
Balance in AOCI as of June 30, 2021 | | Balance in AOCI as of June 30, 2021 | | | $ | 0.5 | | | $ | 1.4 | | | $ | 1.9 | |
Change in Fair Value Recognized in AOCI | Change in Fair Value Recognized in AOCI | | | — | | | — | | | — | | Change in Fair Value Recognized in AOCI | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | Amount of (Gain) Loss Reclassified from AOCI | | | Amount of (Gain) Loss Reclassified from AOCI | | |
| Interest Expense (b) | Interest Expense (b) | | | 1.4 | | | — | | | 1.4 | | Interest Expense (b) | | | 0.4 | | | — | | | 0.4 | |
Amortization of Prior Service Cost (Credit) | Amortization of Prior Service Cost (Credit) | | | — | | | (1.5) | | | (1.5) | | 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 | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 1.4 | | | (1.4) | | | — | | Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | 0.4 | | | (0.5) | | | (0.1) | |
Income Tax (Expense) Benefit | Income Tax (Expense) Benefit | | | 0.3 | | | (0.3) | | | — | | Income Tax (Expense) Benefit | | | 0.1 | | | (0.1) | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 1.1 | | | (1.1) | | | — | | Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | 0.3 | | | (0.4) | | | (0.1) | |
Net Current Period Other Comprehensive Income (Loss) | Net Current Period Other Comprehensive Income (Loss) | | | 1.1 | | | (1.1) | | | — | | Net Current Period Other Comprehensive Income (Loss) | | | 0.3 | | | (0.4) | | | (0.1) | |
Balance in AOCI as of September 30, 2020 | | | $ | (0.7) | | | $ | (0.6) | | | $ | (1.3) | | |
Balance in AOCI as of September 30, 2021 | | Balance in AOCI as of September 30, 2021 | | | $ | 0.8 | | | $ | 1.0 | | | $ | 1.8 | |
| | | | | | | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 30, 2022 | | | | Interest Rate | | and OPEB | | Total |
| | | (in millions) |
Balance in AOCI as of December 31, 2021 | | | | $ | 1.2 | | | $ | 5.5 | | | $ | 6.7 | |
Change in Fair Value Recognized in AOCI | | | | — | | | — | | | — | |
Amount of (Gain) Loss Reclassified from AOCI | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.5) | | | (1.5) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | — | | | (1.5) | | | (1.5) | |
Income Tax (Expense) Benefit | | | | — | | | (0.3) | | | (0.3) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | — | | | (1.2) | | | (1.2) | |
Net Current Period Other Comprehensive Income (Loss) | | | | — | | | (1.2) | | | (1.2) | |
Balance in AOCI as of September 30, 2022 | | | | $ | 1.2 | | | $ | 4.3 | | | $ | 5.5 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
| | | | Cash Flow Hedge – | | Pension | | |
Nine Months Ended September 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) | | | | 1.4 | | | — | | | 1.4 | |
Amortization of Prior Service Cost (Credit) | | | | — | | | (1.5) | | | (1.5) | |
| | | | | | | | |
Reclassifications from AOCI, before Income Tax (Expense) Benefit | | | | 1.4 | | | (1.5) | | | (0.1) | |
Income Tax (Expense) Benefit | | | | 0.3 | | | (0.3) | | | — | |
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit | | | | 1.1 | | | (1.2) | | | (0.1) | |
Net Current Period Other Comprehensive Income (Loss) | | | | 1.1 | | | (1.2) | | | (0.1) | |
Balance in AOCI as of September 30, 2021 | | | | $ | 0.8 | | | $ | 1.0 | | | $ | 1.8 | |
(a)The change in fair value includes $(1)$(4) million and $(1) million, respectively, for the three months ended September 30, 2022 and 2021 and 2020$(9) million and $(5) million and $6 million, respectively, for the nine months ended September 30, 20212022 and 20202021 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.
4. RATE MATTERS
The disclosures in this note apply to all Registrants unless indicated otherwise.
As discussed in the 20202021 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20202021 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 20212022 and updates the 20202021 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
The Oklaunion Power Station was retired in September 2020 and sold to a nonaffiliated third-party in October 2020. As of September 30, 2021, PSO has a regulatory asset for accelerated depreciation pending approval recorded on its balance sheet of $33 million. PSO has requested recovery of the Oklaunion Power Station as part of its 2021 Oklahoma base rate case. See “2021 Oklahoma Base Rate Case” section below for additional information.
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 theauthorized recovery of SWEPCo’s Texas jurisdictional share of Welsh Plant, Unit 2.2, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $7 million in 2017. See “2016 Texas Base Rate Case” section 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. See “2020 Louisiana Base Rate Case” section below for additional information. As of September 30, 2021,2022, SWEPCo hashad 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.
In December 2021, the Dolet Hills Power Station was retired. As part of the 2020 Texas Base Rate Case, the PUCT authorized recovery of SWEPCo’s Texas jurisdictional share of the Dolet Hills Power Station, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $12 million in 2021. As part of the 2021 Arkansas Base Rate Case, the APSC authorized recovery of SWEPCo’s Arkansas jurisdictional share of the Dolet Hills Power Station over five years, but denied SWEPCo the ability to earn a return on this investment resulting in a disallowance of $2 million in the second quarter of 2022. Also, the APSC did not rule on the prudency of the early retirement of the Dolet Hills Power Station, which will be addressed in a future proceeding. SWEPCo has requested recovery of the Dolet Hills Power Station in the Louisiana jurisdiction through the 2020 Louisiana Base Rate Case. As of September 30, 2022, SWEPCo had a regulatory asset of $55 million, pending approval, recorded on its balance sheet related to the Louisiana and FERC jurisdictional shares of the Dolet Hills Power Station. The Dolet Hills Power Station is currently being recovered through 2026 in the Louisiana jurisdiction, through 2027 in the Arkansas jurisdiction and through 2046 in the Texas jurisdiction. See “2020 Texas Base Rate Case”, “2020 Louisiana Base Rate Case” and “2021 Arkansas Base Rate Case” sections 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 the 2021 Oklahoma Base Rate Case, PSO has requested recovery ofwill continue to recover Northeastern Plant, Unit 3 as part of its 2021 Oklahoma base rate case. See “2021 Oklahoma Base Rate Case” section below for additional information.
SWEPCothrough 2040.
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 September 30, 2021,2022, of generating facilities planned for early retirement:
| Plant | Plant | | | Net Book Value | | Accelerated Depreciation Regulatory Asset | | | Cost of Removal Regulatory Liability | | Projected Retirement Date | | Current Authorized Recovery Period | | Annual Depreciation (a) | Plant | | | Net Book Value | | Accelerated Depreciation Regulatory Asset | | | Cost of Removal Regulatory Liability | | Projected Retirement Date | | Current Authorized Recovery Period | | Annual Depreciation (a) |
| | | | (dollars in millions) | | | | (dollars in millions) |
Northeastern Plant, Unit 3 | Northeastern Plant, Unit 3 | | | $ | 175.1 | | | $ | 123.6 | | | | $ | 20.0 | | (b) | | 2026 | | (c) | | $ | 14.9 | | Northeastern Plant, Unit 3 | | | $ | 143.7 | | | $ | 141.4 | | | | $ | 20.2 | | (b) | | 2026 | | (c) | | $ | 14.9 | |
Dolet Hills Power Station | | | 13.0 | | | 126.8 | | | | 24.4 | | | 2021 | | (d) | | 7.8 | | |
Pirkey Power Plant | | | 135.4 | | | 68.0 | | | | 39.2 | | | 2023 | | (e) | | 13.5 | | |
Pirkey Plant | | Pirkey Plant | | | 65.0 | | | 150.7 | | | | 39.6 | | | 2023 | | (d) | | 12.5 | |
Welsh Plant, Units 1 and 3 | Welsh Plant, Units 1 and 3 | | | 493.7 | | | 35.6 | | | | 58.2 | | (f) | | 2028 | | (g) | | 33.1 | | Welsh Plant, Units 1 and 3 | | | 432.3 | | | 75.7 | | | | 58.2 | | (e) | | 2028 | | (f) | | 39.8 | |
(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.
(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)(e)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)(f)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 ceased in October 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. In December 2021, the Dolet Hills Power Station was retired. While in operation, DHLC provided 100% of the fuel supply to Dolet Hills Power Station.
The remaining book value of Dolet Hills Power Station non-fuel costsrelated assets are recoverable by SWEPCo through a combination of base rates.rates and rate riders. As of September 30, 2021,2022, SWEPCo’s share of the net investment in the Dolet Hills Power Station is $146was $113 million, including CWIP and materials and supplies, beforenet of cost of removal.removal collected in rates.
Fuel costs incurred by the Dolet Hills Power Station are recoverable by SWEPCo through active fuel clauses. Underclauses and are subject to prudency determinations by the fuel agreements, SWEPCo’s fuel inventory and unbilled fuel costs from mining related activities were $44 million as of September 30, 2021. Also, as of September 30, 2021, SWEPCo had a net under-recovered fuel balance of $39 million, excluding impactsvarious commissions. After closure of the February 2021 severe winter weather event, which includes fuel consumed atDHLC mining operations and the Dolet Hills Power Station. Additional operational,Station, additional reclamation and other land-related costs incurred by DHLC and Oxbow will continue to be billed to SWEPCo and included in futureexisting fuel clauses. As of September 30, 2022, SWEPCo had a net under-recovered fuel balance of $236 million, inclusive of costs related to the Dolet Hills Power Station billed by DHLC, but excluding impacts of the February 2021 severe winter weather event.
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 August 2022, the LPSC staff filed testimony recommending fuel disallowances of $72 million, including denial of recovery of the $30 million deferral, with refunds to customers over five years. In September 2022, SWEPCO filed rebuttal testimony addressing the LPSC staff recommendations.
In March 2021, the APSC approved fuel rates that provide recovery of $20 million for the Arkansas share of the 2021 Dolet Hills Power Station fuel costs over five years through the existing fuel clause.
In August 2022, SWEPCo filed a fuel reconciliation with the PUCT covering the fuel period of January 1, 2020 through December 31, 2021.
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.clauses and are subject to prudency determinations by the various commissions. As of September 30, 2021,2022, SWEPCo’s share of the net investment in the Pirkey Power Plant is $203was $216 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 $108$49 millionas of September 30, 2021. Also, as2022. As of September 30, 2021,2022, SWEPCo had a net under-recovered fuel balance of $39$236 million, inclusive of costs related to the Pirkey Plant billed by Sabine, but excluding impacts of the February 2021 severe winter weather event, which includes fuel consumed atevent. Upon cessation of lignite deliveries by Sabine to the Pirkey Power Plant. AdditionalPlant, additional operational, reclamation and other land-related costs incurred by Sabine will be billed to SWEPCo and included in futureexisting fuel clauses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition..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 is currently awaiting approval from the PUCT. If additional costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Regulatory Assets Pending Final Regulatory Approval (Applies to all Registrants except AEPTCo)
| | | AEP | | AEP |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | | |
Regulatory Assets Currently Earning a Return | Regulatory Assets Currently Earning a Return | | | | | Regulatory Assets Currently Earning a Return | | | | |
Pirkey Plant Accelerated Depreciation | | Pirkey Plant Accelerated Depreciation | | $ | 150.7 | | | $ | 87.0 | |
Unrecovered Winter Storm Fuel Costs (a) | Unrecovered Winter Storm Fuel Costs (a) | | $ | 1,106.3 | | | $ | — | | Unrecovered Winter Storm Fuel Costs (a) | | 126.1 | | | 430.2 | |
| Welsh Plant, Units 1 and 3 Accelerated Depreciation | | Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 75.7 | | | 45.9 | |
Dolet Hills Power Station Accelerated Depreciation | Dolet Hills Power Station Accelerated Depreciation | | 126.8 | | | 71.2 | | Dolet Hills Power Station Accelerated Depreciation | | 54.7 | | | 72.3 | |
Pirkey Power Plant Accelerated Depreciation | | 68.0 | | | 12.2 | | |
Kentucky Deferred Purchase Power Expenses | | 45.9 | | | 41.3 | | |
Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 35.6 | | | 3.6 | | |
| Plant Retirement Costs – Unrecovered Plant, Louisiana | Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | | Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | |
Oklaunion Power Station Accelerated Depreciation | | 33.0 | | | 34.4 | | |
| | Dolet Hills Power Station Fuel Costs - Louisiana | Dolet Hills Power Station Fuel Costs - Louisiana | | 20.3 | | | — | | Dolet Hills Power Station Fuel Costs - Louisiana | | 31.8 | | | 30.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 25.5 | | | 22.8 | | Other Regulatory Assets Pending Final Regulatory Approval | | 21.2 | | | 9.2 | |
Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | Storm-Related Costs | | 325.8 | | | 134.2 | | Storm-Related Costs | | 306.5 | | | 241.8 | |
2017-2019 Virginia Triennial Under-Earnings | | 2017-2019 Virginia Triennial Under-Earnings | | 37.0 | | | — | |
Plant Retirement Costs – Asset Retirement Obligation Costs | Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | | Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
2020-2022 Virginia Triennial Under-Earnings | | 2020-2022 Virginia Triennial Under-Earnings | | 25.3 | | | 15.1 | |
COVID-19 | COVID-19 | | 14.0 | | | 24.9 | | COVID-19 | | 8.7 | | | 11.2 | |
Asset Retirement Obligation - Louisiana | | 10.0 | | | 9.1 | | |
Renewable Energy Portfolio Standards Costs - Virginia | | Renewable Energy Portfolio Standards Costs - Virginia | | — | | | 2.1 | |
| | Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 32.6 | | | 27.4 | | Other Regulatory Assets Pending Final Regulatory Approval | | 42.4 | | | 41.8 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | $ | 1,904.9 | | | $ | 442.2 | | Total Regulatory Assets Pending Final Regulatory Approval | $ | 941.2 | | | $ | 1,048.6 | |
(a) Includes $37 million and $63 million of unrecovered winter storm fuel costs recorded as a current regulatory asset as of September 30, 2022 and December 31, 2021, respectively.
(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 | | AEP Texas |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| Regulatory Assets Currently Earning a Return | Regulatory Assets Currently Earning a Return | | Regulatory Assets Currently Earning a Return | |
Advanced Metering System | | $ | 16.6 | | | $ | 16.3 | | |
Mobile Generation Lease Payments | | Mobile Generation Lease Payments | | $ | 9.2 | | | $ | — | |
Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | Storm-Related Costs | | 22.7 | | | 0.8 | | Storm-Related Costs | | 27.0 | | | 22.4 | |
Vegetation Management Program | Vegetation Management Program | | 5.2 | | | 3.8 | | Vegetation Management Program | | 5.2 | | | 5.2 | |
Texas Retail Electric Provider Bad Debt Expense | Texas Retail Electric Provider Bad Debt Expense | | 4.1 | | | — | | Texas Retail Electric Provider Bad Debt Expense | | 4.1 | | | 4.1 | |
COVID-19 | COVID-19 | | 3.9 | | | 10.5 | | COVID-19 | | 3.8 | | | 2.1 | |
Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 5.3 | | | 1.5 | | Other Regulatory Assets Pending Final Regulatory Approval | | 8.2 | | | 7.4 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 57.8 | | | $ | 32.9 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 57.5 | | | $ | 41.2 | |
| | | APCo | | APCo |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| Regulatory Assets Currently Earning a Return | Regulatory Assets Currently Earning a Return | | Regulatory Assets Currently Earning a Return | |
COVID-19 – Virginia | COVID-19 – Virginia | | $ | 6.6 | | | $ | 3.7 | | COVID-19 – Virginia | | $ | 7.0 | | | $ | 6.8 | |
| Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | | 59.8 | | | 3.4 | | |
Storm-Related Costs - West Virginia | | Storm-Related Costs - West Virginia | | 69.9 | | | 53.7 | |
2017-2019 Virginia Triennial Under-Earnings | | 2017-2019 Virginia Triennial Under-Earnings | | 37.0 | | | — | |
Plant Retirement Costs – Asset Retirement Obligation Costs | Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | | Plant Retirement Costs – Asset Retirement Obligation Costs | | 25.9 | | | 25.9 | |
COVID-19 – West Virginia | | 0.4 | | | 1.5 | | |
Environmental Expense Deferral - Virginia | | — | | | 9.3 | | |
2020-2022 Virginia Triennial Under-Earnings | | 2020-2022 Virginia Triennial Under-Earnings | | 25.3 | | | 15.1 | |
| Renewable Energy Portfolio Standards Costs - Virginia | | Renewable Energy Portfolio Standards Costs - Virginia | | — | | | 2.1 | |
| Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 1.2 | | | — | | Other Regulatory Assets Pending Final Regulatory Approval | | 1.6 | | | 1.5 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 93.9 | | | $ | 43.8 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 166.7 | | | $ | 105.1 | |
| | | | I&M | | | I&M |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | | |
Regulatory Assets Currently Earning a Return | Regulatory Assets Currently Earning a Return | | Regulatory Assets Currently Earning a Return | |
Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | $ | — | | | $ | 0.5 | | Other Regulatory Assets Pending Final Regulatory Approval | | $ | 0.1 | | | $ | 0.1 | |
Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
COVID-19 | COVID-19 | | 1.7 | | | 3.8 | | COVID-19 | | 0.1 | | | 1.7 | |
| Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 1.7 | | | — | | Other Regulatory Assets Pending Final Regulatory Approval | | 1.7 | | | 1.9 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 3.4 | | | $ | 4.3 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 1.9 | | | $ | 3.7 | |
| | | | OPCo | | | OPCo |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | | |
Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs | Storm-Related Costs | | $ | 5.5 | | | $ | 4.0 | | Storm-Related Costs | | $ | 32.5 | | | $ | 3.8 | |
COVID-19 | | 1.9 | | | 4.4 | | |
| Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | — | | Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | — | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 7.5 | | | $ | 8.4 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 32.6 | | | $ | 3.8 | |
| | | | PSO | | | PSO |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | | |
Regulatory Assets Currently Earning a Return | | | | | |
Unrecovered Winter Storm Fuel Costs (a) | | $ | 673.2 | | | $ | — | | |
Oklaunion Power Station Accelerated Depreciation | | 33.0 | | | 34.4 | | |
| | Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
| Storm-Related Costs | Storm-Related Costs | | 29.3 | | | 15.8 | | Storm-Related Costs | | $ | 24.3 | | | $ | 13.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 0.9 | | | 0.3 | | Other Regulatory Assets Pending Final Regulatory Approval | | 0.1 | | | 0.3 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 736.4 | | | $ | 50.5 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 24.4 | | | $ | 14.2 | |
(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..
| | | SWEPCo | | SWEPCo |
| | September 30, | | December 31, | | September 30, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Noncurrent Regulatory Assets | Noncurrent Regulatory Assets | | (in millions) | Noncurrent Regulatory Assets | | (in millions) |
| | | | | | | | | | |
Regulatory Assets Currently Earning a Return | Regulatory Assets Currently Earning a Return | | | | | Regulatory Assets Currently Earning a Return | | | | |
Pirkey Plant Accelerated Depreciation | | Pirkey Plant Accelerated Depreciation | | $ | 150.7 | | | $ | 87.0 | |
Unrecovered Winter Storm Fuel Costs (a) | Unrecovered Winter Storm Fuel Costs (a) | | $ | 433.1 | | | $ | — | | Unrecovered Winter Storm Fuel Costs (a) | | 126.1 | | | 430.2 | |
| Welsh Plant, Units 1 and 3 Accelerated Depreciation | | Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 75.7 | | | 45.9 | |
Dolet Hills Power Station Accelerated Depreciation | Dolet Hills Power Station Accelerated Depreciation | | 126.8 | | | 71.2 | | Dolet Hills Power Station Accelerated Depreciation | | 54.7 | | | 72.3 | |
Pirkey Power Plant Accelerated Depreciation | | 68.0 | | | 12.2 | | |
Welsh Plant, Units 1 and 3 Accelerated Depreciation | | 35.6 | | | 3.6 | | |
Plant Retirement Costs – Unrecovered Plant, Louisiana | Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | | Plant Retirement Costs – Unrecovered Plant, Louisiana | | 35.2 | | | 35.2 | |
Dolet Hills Power Station Fuel Costs- Louisiana | Dolet Hills Power Station Fuel Costs- Louisiana | | 20.3 | | | — | | Dolet Hills Power Station Fuel Costs- Louisiana | | 31.8 | | | 30.9 | |
Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 2.3 | | | 2.2 | | Other Regulatory Assets Pending Final Regulatory Approval | | 4.9 | | | 2.4 | |
Regulatory Assets Currently Not Earning a Return | Regulatory Assets Currently Not Earning a Return | | | | | Regulatory Assets Currently Not Earning a Return | | | | |
Storm-Related Costs | Storm-Related Costs | | 155.4 | | | 99.3 | | Storm-Related Costs | | 151.3 | | | 148.0 | |
Asset Retirement Obligation - Louisiana | Asset Retirement Obligation - Louisiana | | 10.0 | | | 9.1 | | Asset Retirement Obligation - Louisiana | | 11.3 | | | 10.3 | |
| Other Regulatory Assets Pending Final Regulatory Approval | Other Regulatory Assets Pending Final Regulatory Approval | | 19.3 | | | 14.5 | | Other Regulatory Assets Pending Final Regulatory Approval | | 14.9 | | | 18.4 | |
Total Regulatory Assets Pending Final Regulatory Approval | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 906.0 | | | $ | 247.3 | | Total Regulatory Assets Pending Final Regulatory Approval | | $ | 656.6 | | | $ | 880.6 | |
(a)SWEPCo has an active Includes $37 million and $63 million of unrecovered winter storm fuel clause that allows for the recoverycosts recorded as a current regulatory asset as of prudently incurred fuelSeptember 30, 2022 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.December 31, 2021, respectively.
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 storm restoration costs are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | September 30, 2021 |
Company | | Jurisdiction | | Capital | | O&M | | Regulatory Asset | | Total |
| | | | (in millions) |
APCo | | Virginia | | $ | 8.1 | | | $ | 2.2 | | | $ | 6.6 | | | $ | 16.9 | |
APCo | | West Virginia | | 23.5 | | | — | | | 47.0 | | | 70.5 | |
SWEPCo | | Louisiana | | 6.0 | | | — | | | 45.4 | | | 51.4 | |
KPCo | | Kentucky | | 29.0 | | | 5.0 | | | 42.6 | | | 76.6 | |
| | Total | | $ | 66.6 | | | $ | 7.2 | | | $ | 141.6 | | | $ | 215.4 | |
The amounts in the table above represents costs as of September 30, 2021. 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 is expected to seek recovery in separate filings. In October 2021, SWEPCo requested recovery of these storm costs, in addition to storm costs from Hurricanes Delta and Laura, in a filing with the LPSC. As part of the filing, SWEPCo requested recovery of the carrying charges on the regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. If any of the
restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
February 2021 Severe Winter Weather Impacts in SPP (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) | | $ | 673.2 | | | $ | 433.1 | | (b) | $ | 1,106.3 | |
Wholesale Customers | | — | | | 55.8 | | | 55.8 | |
Total | | $ | 673.2 | | | $ | 488.9 | | | $ | 1,162.1 | |
(a)These costs were deferred as regulatory assets as of September 30, 2021.
(b)SWEPCo’s balance consists of $107 million, $151 million and $175 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. SWEPCo is recovering these fuel costs at an interim carrying charge of 0.8%. Also in April 2021, SWEPCo filed testimony supporting a five-year recovery with a carrying charge of 6.05% which has been supported by APSC staff. Various other parties have recommended recovery periods ranging from 5-20 years with a carrying charge of 1.65%. The APSC ordered more testimony regarding the option of utilizing securitization to recover the fuel costs. SWEPCo is awaiting a decision from the APSC. 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 is recovering these fuel costs at an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
In April 2021, the OCC approved a waiver for PSO allowing the deferral of the extraordinary fuel and purchase of electricity costs, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma to permit securitization of 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. The application requests an order on the prudency of the extraordinary fuel and purchase of electricity costs and a
carrying charge of the commission authorized weighted average cost of capital until securitization bonds can be issued. In October 2021, OCC staff and intervenors filed testimony supporting securitization of these costs and a carrying charge until costs are securitized ranging from the interim rate of 0.75% to the actual cost of capital used to finance the costs of 2.32%. In addition, OCC staff supported the prudency of PSO's requested costs while one intervenor recommended disallowances of up to $40 million. A procedural schedule has been set with an ALJ report to be filed in January 2022. An order from the OCC is expected in the first quarter of 2022.
In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application supported a five-year recovery at a carrying charge of 7.18%. In October 2021, various intervenors filed testimony supporting a five-year recovery with a carrying charge ranging from 0.082% to 1.625%. A hearing with the PUCT is scheduled for November 2021.
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 September 30, 2021, $56 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 nine months ended September 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 September 30, 2021, AEP’s electric operating companies have resumed customary disconnection practices in all regulated jurisdictions with the exception of residential customers in Virginia. AEP continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices once available relief funds are received from the state. 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 September 30, 2021,2022, AEP Texas’ cumulative revenues from interim base rate increases that are subject to review is approximately $229$524 million. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. AEP Texas is required to file for a comprehensive rate review no later than April 5, 2024.
APCo and WPCo Rate Matters (Applies to AEP and APCo)
2017-2019 Virginia Triennial Review
In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 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,March 2021, 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 errorappeal 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. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the assignments of error filed by APCo in March 2021. In October 2021, the Virginia SCC and certainadditional intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignments of errorthe items appealed by APCo in its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with the items appealed by an intervenor’ s assignments of errorintervenor in a separate appeal of the same decision. In March 2022, oral arguments were held at the Virginia Supreme Court.
In August 2022, the Virginia Supreme Court issued its opinion on submitted appeals of APCo’s 2017-2019 Virginia Triennial Review concluding that the Virginia SCC: a) erred in finding it was not reasonable for APCo ultimately seeks an increaseto record all remaining costs associated with early retirement of certain coal-fired generating plants in basethe 2017-2019 earnings test period, b) did not err by ordering APCo to retroactively implement depreciation rates through its appealfor the years 2018 and 2019 and c) did not err in finding that APCo’s affiliate costs from OVEC were reasonable. The Virginia Supreme Court then remanded the issue regarding the retired coal-fired plants back to the Virginia SCC for further proceedings.
In September 2022, and in response to the Virginia Supreme Court. Among other issues, this appealCourt opinion and subsequent Virginia SCC order initiating a remand proceeding, APCo submitted with the Virginia SCC: (a) an updated 2017-2019 Virginia earnings calculation resulting in a proposed $37 million regulatory asset related to previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band, (b) an updated requested annual base rate increase of $41 million effective October 2022 and (c) a requested rider to recover, over the period October 2022 through January 2024, approximately $72 million related to an APCo Virginia base rate increase for the period January 2021 through September 2022. APCo’s requested $41 million annual base rate increase includes
approximately $12 million related to the recovery of APCo’s requestregulatory asset for proper treatmentpreviously incurred costs as a result of earning below its 2017-2019 authorized ROE band. APCo implemented interim base rate and rider rate increases effective October 2022, both of which are subject to refund and review by the Virginia SCC. An order from the Virginia SCC in the remand proceeding is expected in the fourth quarter of 2022.
In September 2022, APCo expensed the remaining $25 million closed coal plant regulatory asset that was previously ordered by the Virginia SCC and recorded a $37 million regulatory asset for previously incurred costs that APCo is expecting to recover as a result of earning below its 2017-2019 authorized ROE band. APCo’s October 2022 through January 2024 net income, cash flows and financial condition is expected to be positively impacted pending the Virginia SCC’s order on APCo’s requested base rate and rider rate increases.
2020-2022 Virginia Triennial Review
In March 2023, APCo will submit its required Virginia earnings test calculation for the 2020-2022 Triennial Review period. For Triennial Review periods in which a Virginia utility earns below its authorized ROE band, the utility may file to recover expenses incurred, up to the bottom of the closed coal-fired plantauthorized ROE band, related to major storms, the early retirement of fossil fuel generating assets in APCo’s 2017-2019 triennial period, reducing APCo’s earningsand certain projects necessary to comply with state and federal environmental legislation. As of September 2022, APCo has deferred approximately $25 million related to previously incurred costs as a result of the current estimate that APCo will earn below the bottom of its authorized ROE band.band during the 2020-2022 Triennial Review period. If APCo’s appeals regarding treatmentit is determined that APCo has earned above the bottom of its authorized ROE band for the closed coal plants are granted by the Virginia Supreme Court,2020-2022 Triennial Review period it could initially reduce future net income and cash flows 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.conditions.
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, that APCo close these generating facilities at the end of 2028.
In August 2021, the Virginia SCC issued an order approving APCo’s request to constructrecovery of CCR-related operation and maintenance expenses and investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order also denied APCo’s request to constructrecover the cost of ELG investments and denied recovery of previously incurred ELG costs.costs, but did not preclude APCo may refilefrom refiling for approval. In March 2022, APCo refiled for approval to recover the cost of the ELG investments and previously incurred ELG costs. Intervenor testimony was submitted in August 2022 recommending the denial of ELG cost recovery. In October 2022, a Virginia Hearing Examiner recommended that the Virginia SCC approve recovery of APCo’s requested ELG investment costs at a later date.Amos and Mountaineer Plants. Management expects to receive an order from the Virginia SCC in the fourth quarter of 2022.
Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In SeptemberOctober 2021, APCo submitted a filing with the WVPSCdue to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the initial rejection by the Virginia SCC of the Virginia jurisdictional share of thepreviously rejecting those ELG investments, APCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plants. In October 2021, the WVPSC affirmed its August 2021issued an order approving the construction of CCR/ELG investments and directeddirecting APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The WVPSC’s order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. InThe October 2021 an intervenor filed a petitionorder further states that unless the Virginia jurisdictional customers of APCo pay for reconsideration attheir share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the WVPSC requesting clarification on certain aspectsbenefit of the order, primarilycapacity and energy made possible by those improvements and operating the Amos and Mountaineer Plants beyond 2028 should benefit only West Virginia and FERC jurisdictional allocation of future operating expenses and plantcustomers who have shared in paying for those costs.
APCo expects the total Amos and Mountaineer Plant ELG investment, includingexcluding AFUDC, to be approximately $177$162 million. As of September 30, 2021,2022, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $19$62 million.
If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plantsPlants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.
2021 and 2022 ENEC (Expanded Net Energy Cost) Filings
In April 2021, APCo and WPCo (the Companies) requested a $73 million annual increase in ENEC rates based on a cumulative combined $55 million ENEC under-recovery as of February 28, 2021 and a combined $18 million increase in projected ENEC costs for the period September 2021 through August 2022. In September 2021, the WVPSC issued an order approving a $7 million overall increase in ENEC rates, including an approval for recovery of the Companies’ cumulative $55 million ENEC under-recovery balance and a $48 million reduction in projected costs for the period September 2021 through August 2022. Subsequently, the Companies submitted a request for reconsideration of this order, identifying flaws in the WVPSC’s calculation of forecasted future year fuel expense and purchased power costs.
In March 2022, the WVPSC issued an order granting the Companies’ request for reconsideration, in part, and approving $31 million in projected costs for the period September 2021 through August 2022. The order also reopened the 2021 ENEC case to require the Companies to explain the significant growth in the reported under-recovery of ENEC costs and to provide various other information including revised projected costs for the period March 2022 through August 2022. Also, in March 2022, the Companies filed testimony providing the information requested in the WVPSC’s order and requested a $155 million annual increase in ENEC rates effective May 1, 2022. In May 2022, the WVPSC issued an order approving a $93 million overall increase to ENEC rates to recover projected annual ENEC costs. However, the WVPSC stated that actual and projected ENEC costs are still subject to a prudency review.
In April 2022, the Companies submitted their 2022 annual ENEC filing with the WVPSC requesting a $297 million annual increase in ENEC revenues, inclusive of the previously requested $155 million increase, effective September 1, 2022.
In September 2022, following an agreed upon delay in the proceedings of the Companies’ 2022 ENEC case, certain intervenors submitted testimony recommending disallowances of at least $83 million to the Companies’ historical period ENEC under-recovery balance along with proposals to either securitize the Companies’ remaining ENEC balance or defer recovery of this balance beyond the traditional one-year period. West Virginia Staff recommended a $13 million increase in ENEC rates pending the outcome of the ENEC prudency review. Management expects to receive a WVPSC order on the Companies’ 2022 ENEC filing in the fourth quarter of 2022 and a separate WVPSC order on the prudency review of the Companies’ ENEC costs in the first quarter of 2023. As of September 30, 2022, the Companies’ cumulative ENEC under-recovery was $430 million. If any deferred ENEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
June 2022 West Virginia Storm Costs
In June 2022, the West Virginia service territories of APCo and WPCo (the Companies) were impacted by strong winds from multiple storms resulting in system damages and power outages. As of September 30, 2022, the Companies incurred and deferred an estimated $15 million in incremental distribution operation and maintenance expenses related to service restoration efforts. The Companies will seek recovery of these deferrals in future filings. If any of the storm restoration costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
ETT Rate Matters (Applies to AEP)
ETT Interim Transmission Rates
AEP has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next base rate proceeding. Through September 30, 2021,2022, AEP’s share of ETT’s cumulative revenues that are subject to review is approximately $1.3$1.5 billion. A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. ETT is required to file for a comprehensive rate review no later than February 1, 2023, during which the $1.3$1.5 billion of cumulative revenues above will be subject to review.
I&M Rate Matters (Applies to AEP and I&M)
Michigan Power Supply Cost Recovery (PSCR) Reconciliation
In April 2022, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) for I&M’s PSCR reconciliation for the 12-month period ending December 31, 2020, recommending the MPSC disallow approximately $8 million of purchased power costs that I&M incurred under the Inter-Company Power Agreement with OVEC and the Unit Power Agreement with AEGCo. In May 2022, I&M submitted exceptions to the ALJ’s PFD related to the recommended disallowance of purchased power costs described above. I&M anticipates that the MPSC will issue a final decision in the fourth quarter of 2022. Management is unable to predict the impact, if any, that the MPSC’s final decision may have on future results of operations, financial condition and cash flows.
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,August 2022, I&M submitted its FAC filing and earnings test evaluation for the period ended May 2021,2022, which calculated a credit due to customers of $9$14 million. In September 2021,October 2022, the IURC approved the FAC filing and earnings test evaluation, with the credit to customers starting in October 2021November 2022 through the FAC.
2021 Indiana Base Rate Case2022 Michigan Integrated Resource Plan (IRP) Filing
In July 2021,February 2022, I&M filed a request with the IURCMPSC for a $104 million annual increaseapproval of its 2022 IRP. Included in Indiana base rates based upon a proposed 10% ROE.that filing were requests for approval and deferral of costs associated with resources commencing construction within three years of the Commission’s order in the filing. These resources include the new generation resources expected to be in-service by 2028, and demand-side resources, including load management programs and conservation voltage reduction investments. I&M proposed a phased-in annual increase in ratesis also requesting MPSC approval of $73 million effective in May 2022I&M’s Rockport Unit 2 transition plan consistent with that approved by the remaining $31 million annual increase in rates to be effective January 2023. The proposed annual increase includes $7 millionIURC, including certain cost recovery related to an annual increase in depreciation expense, driven by increased depreciation ratesremaining net book value of leasehold improvements made during the term of the Rockport Unit 2 lease and proposed investments. The request also includesfuture use of Rockport Unit 2 as a new AMI ridercapacity resource. In addition, I&M has made requests for proposed meter projects.approval of a financial incentive on certain power purchase agreements and load management programs. As of September 30, 2022, I&M’s total net book value for these Rockport Unit 2 leasehold improvements was $102 million.
In October 2021, intervenors submitted testimony recommending an annual decrease in Indiana base rates ranging from $13 millionJune 2022, intervening parties recommended various adjustments to $68 million based upon a ROE ranging from 9.1%I&M’s proposals, including the process I&M would use to 9.3%. Among other issues, receive approval of new generation resources, changes to or denial of requested financial incentives and requests for deferral and pre-approval of costs. Specific to I&M’s Rockport Unit 2 transition plan, certain
intervening parties recommended that the IURC rejectMPSC order I&M to credit back to Michigan ratepayers the following: (a)jurisdictional share of post-lease revenues in excess of costs from Rockport Unit 2’s operations as a merchant facility and that I&M’s proposed re-allocation of capacity costs related to the 2020 loss of&M only receive a significant FERC wholesale contract, (b) continued recovery of apost-lease debt return on remaining net book value of Rockport Unit 2 leasehold improvements onceimprovements. A hearing with the related lease endsMPSC was held in DecemberAugust 2022.
Management currently anticipates that the MPSC will issue an order on I&M’s 2022 (c) inclusionMichigan IRP filing in the first quarter of net operating loss2023. Any disallowance or reduction in rate base, (d) the proposed new AMI rider and (e) inclusionrecovery of prepaid pension and OPEB assets in rate base.the I&M rebuttal testimony is due in November 2021. If any costs are not recoverable, itMichigan jurisdictional share of the Rockport Unit 2 leasehold improvements 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. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million. In December 2020 and February 2021, WPCo and KPCo filed requests with the WVPSC and KPSC, respectively, to obtain the regulatory approvals necessary to implement CCR and ELG compliance plans and seek recovery of the estimated $132 million investment for the Mitchell Plant that would allow the plant to continue operating beyond 2028. Within those requests, WPCo and KPCo also filed a $25 million alternative to implement only the CCR-related investments with the WVPSC and KPSC, respectively, which would allow the Mitchell Plant to continue operating only through 2028.
In July 2021, the KPSC issued an order approving the CCR only alternative and rejecting the full CCR and ELG compliance plan. In May 2022, the KPSC approved recovery of the Kentucky jurisdictional share of ELG costs incurred at the Mitchell Plant prior to July 15, 2021.
In August 2021, the WVPSC approved the full CCR and ELG compliance plan for the WPCo share of the Mitchell Plant. In September 2021, WPCo submitted a filing with the WVPSC to reopen the CCR/ELG case that was approved by the WVPSC in August 2021. Due to the rejection by the KPSC of the KPCo share of the ELG investments, WPCo requested the WVPSC consider approving the construction and recovery of all ELG costs at the plant. In October 2021, the WVPSC affirmed its August 2021 order approving the construction of CCR/ELG investments and directed WPCo to proceed with CCR/ELG compliance plans that would allow the plant to continue operating beyond 2028. The WVPSC’s order further states WPCo will not share capacity and energy from the plant with KPCo customers if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plant to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that WPCo will be given the opportunity to recover, from its customers, the ELG and new capital and operating costs arising solely from the WVPSC's directive to operate the plant beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October 2021, an intervenor filed a petitionThe WVPSC’s order further states that unless KPCo pays for reconsideration atits share of costs for ELG improvements and costs necessary to continue operations beyond 2028, the WVPSC requesting clarification on certain aspectsbenefit of the order, primarily the jurisdictional allocation of futurecapacity and energy made possible by those improvements and operating expenses and plant costs.
As of September 30, 2021, KPCo’s share of the Mitchell Plant’s ELG investment balance in CWIP was $2 million. As of September 30, 2021, the net book value of KPCo’s share of the Mitchell Plant before cost of removal including CWIP and inventory, was $587 million.
If any of the ELG costs are not approvedbeyond 2028 should benefit only West Virginia jurisdictional customers who have shared in paying 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.those costs.
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.OVEC Cost Recovery Audits
In November 2020,December 2021, as part of OVEC cost recovery audits pending before the PUCO, staff filed testimony supporting an annual revenue decrease ranging from $102 million to $123 million based upon a 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.positions claiming that costs incurred by OPCo during the 2018-2019 audit period were imprudent and should be disallowed. In May 2022, intervenors filed for rehearing on the 2016-2017 OVEC cost recovery audit period claiming the PUCO’s April 2022 order to adopt the findings of the audit report were unjust, unlawful and unreasonable for multiple reasons, including the position that OPCo recovered imprudently incurred costs. In June 2022, the PUCO granted rehearing on the 2016-2017 audit period for purposes of further consideration. Management disagrees with these claims and is unable to predict the impact, if any, these disputes may have on future results of operations,
financial condition and cash flows. See "OVEC" section of Note 17 in the 2021 Annual Report for additional information on AEP and OPCo’s investment in OVEC.
June 2022 Storm Costs
In March 2021,June 2022, the service territory of OPCo was impacted by strong winds from multiple storms resulting in power outages and damage to the PUCO stafftransmission and variousdistribution infrastructures. As of September 30, 2022, OPCo had incurred approximately $19 million in incremental operation and maintenance costs related to service restoration efforts. The incremental storm restoration costs have been deferred as regulatory assets and OPCo is expected to seek recovery in a future filing. In July 2022, intervenors filed a joint stipulation and settlement agreement withmotion requesting the PUCO. The agreement includesPUCO open 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 andformal investigation into the agreed upon decrease is primarily due topower outages that occurred as 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 continuationresult of the DIR with annual revenue caps of $57 million in 2021, $91 million in 2022, $116 million in 2023June storms and $51 million for the first five months of 2024. Annual revenue caps for the DIR can be increaseddetermine if OPCo achieves certain reliability standards. If the joint stipulationwas negligent 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 in the fourth quarter 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 ESPliable to consumers for damages incurred 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. In September 2021, the third-party consulting company adjusted its findings in the previous audit, indicating that OPCo exceeded its 2019 authorized revenue limit by $3 million. Management disagrees with the audit results and believes that OPCo was below its authorized revenue limit in 2019. If the resultsresult of the auditpower outages. If any of the storm restoration costs are upheld by the PUCO and any refunds to customers or revenue reductions are ordered,not recoverable, it could reduce future net income and cash flows and impact financial condition.
PSO Rate Matters (Applies to AEP and PSO)
February 2021 Oklahoma Base Rate CaseSevere Winter Weather Impacts in SPP
In February 2021, severe winter weather had a significant impact in SPP, resulting in the declaration of Energy Emergency Alert Levels 2 and 3 for the first time in SPP’s history. The winter storm increased the demand for natural gas and restricted the available natural gas supply resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system.
In April 2021, PSO filed a request with the OCC forapproved a $172 million net annual increasewaiver allowing the deferral of PSO’s extraordinary fuel costs and purchases of electricity as regulatory assets, including a carrying charge at an interim rate of 0.75%, over a longer time period than what the FAC traditionally allows. Also in April 2021, legislation was enacted in Oklahoma base rates based upon a 10% ROE. The proposed net annual increase includes: (a) a $57 million annual depreciation expense increase,permitting securitized financing of which $45 million is relatedqualified costs from extreme weather events. This legislation provides certain authority to the accelerated depreciation recoveryOCC to approve amounts to be recovered from the issuance of ratepayer-backed securitized bonds issued by 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.ODFA, an Oklahoma governmental agency. In August 2021, PSO updated its request for a net annual revenue increase to appropriately reflect certain cost reductions and annualized rider revenues transitioning into base rates. PSO’s updated request filed with the OCC is for a $128 million net annual increase in Oklahoma base rates based upon a 10% ROE.
Also, in August 2021, OCC staff and various intervenors filed testimony supporting net annual revenue changes ranging from a $44 million net decrease to a $74 million net increase based upon a ROE of 9.0% to 9.4%. The difference between PSO’s request and OCC staff and intervenor testimony is primarily due to: (a) disallowance of recovery of Oklaunion Power Station or allowing recovery with a debt-only return over Oklaunion Power Station's original useful life of 2046, (b) rejection of PSO’s request to accelerate the recovery of Northeastern Plant, Unit 3 from its original retirement date of 2040 to its projected retirement date of 2026, (c) disallowance of $41 million in SPP transmission expense and denial of prospective tracking of most SPP transmission costs through the SPP transmission tariff, (d) opposition to PSO’s recommendation to include its deferred tax asset associated with net operating loss on a stand-alone tax basis in rate base, (e) a lower recommended ROE and (f) recommendations to discontinue the Distribution and Safety Reliability Rider.
In September 2021,January 2022, PSO, OCC staff and certain intervenors filed a contested joint stipulation and settlement agreement with the OCC that included a net annual revenue increaseto approve the securitization of $51 million based upon a 9.4% ROE. The agreement also included: (a) recoveryPSO’s extraordinary fuel costs and purchases of with a debt return on,electricity. In February 2022, the Oklaunion Power Station regulatory asset through 2046 and continued recovery of Northeastern Plant, Unit 3 through 2040, (b) updated depreciation rates for plant in service, not including coal production plant, (c) approval to defer a weighted average cost of capital carrying charge on PSO’s deferred tax asset associated with net operating loss on a stand-alone tax basis beginning in November 2021 and, contingent upon receipt of a supportive private letter ruling fromOCC approved the IRS, approval to collect the deferral through a rider over a 20-month period, (d) modification of the SPP transmission tariff to reduce the scope of tracked transmission expense and (e) modification of the Distribution Reliability and Safety Rider to limit recovery to previously approved projects not in service as of June 2021. In October 2021, a hearing on the merits of the contested joint stipulation and settlement agreement was held atwhich included a determination that all of PSO’s extraordinary fuel costs and purchases of electricity were prudent and reasonable and also provided a 0.75% carrying charge related to those costs, subject to true-up based on actual financing costs.
In September 2022, PSO received proceeds of $687 million from the OCC.ODFA which issued ratepayer-backed securitization bonds for the purpose of reimbursing PSO for extraordinary fuel costs and purchases of electricity incurred during the February 2021 severe winter weather event, which were previously recorded as Regulatory Assets on PSO’s balance sheet. The securitization bonds are the obligation of the ODFA and there is no recourse against PSO in the event of a bond default, and therefore are not recorded as Long-term Debt on PSO’s balance sheet. PSO will implement interim rates subjectserve as the servicing agent of the bonds and is responsible for the routine billing and collection of the securitization charges and remitting those collections back to refund starting with the November 2021 billing cycle. An order is expected in December 2021. If any of these costsODFA. The securitization charges billed to and collected from customers are not recoverable, it could reduce future net income and cash flows and impact financial condition.included as revenue on PSO’s statement of income. The collections from customers will occur over 20 years.
SWEPCo Rate Matters (Applies to AEP and SWEPCo)
2012 Texas Base Rate Case
In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs.
Upon rehearing in 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, SWEPCo reversed $114 million of a previously recorded regulatory disallowance in 2013. In 2017, the Texas District Court upheld the PUCT’s 2014 order and intervenors filed appeals with the Texas Third Court of Appeals.
In July 2018, the Texas Third Court of Appeals reversed the PUCT’s judgment affirming the prudence of the Turk Plant and remanded the issue back to the PUCT. In January 2019, SWEPCo and the PUCT filed petitions for review with the Texas Supreme Court. In March 2021, the Texas Supreme Court issued an opinion reversing the July 2018 judgment of the Texas Third Court of Appeals and agreeing with the PUCT’s judgment affirming the prudence of the Turk Plant. In addition, the Texas Supreme Court remanded the AFUDC dispute back to the Texas Third Court of Appeals. No parties filed a motion for rehearing with the Texas Supreme Court. In August 2021, the Texas Third Court of Appeals reversed the Texas District Court judgementjudgment affirming the PUCT’s order on AFUDC, concluding that the language of the PUCT’s original 2008 order intended to include AFUDC in the Texas jurisdictional capital cost cap, and remanded the case to the PUCT for future proceedings. SWEPCo disagrees with the Court of Appeals decisiondecision. SWEPCo and expects to submit a Petitionthe PUCT submitted Petitions for Review with the Texas Supreme Court in November 2021. In October 2022, the Texas Supreme Court denied the Petitions for Review submitted by SWEPCo and the PUCT. SWEPCo plans to file a request for rehearing. If SWEPCo’s request for rehearing is denied, the case will be remanded to the PUCT for future proceedings.
IfManagement does not believe a disallowance of capitalized Turk Plant costs or a revenue refund is probable as of September 30, 2022. However, if SWEPCo is ultimately unable to recover capitalized Turk Plant costs including AFUDC in excess of the Texas jurisdictional capital cost cap, it would be expected to result in a pretax net disallowance ranging from $80 million to $100$90 million. In addition, if AFUDC is ultimately determined to be included in the Texas jurisdictional capital cost cap, SWEPCo estimates it may be required to make customer refunds ranging from $0 to $160$180 million related to revenues collected from February 2013 through September 20212022 and such determination may reduce SWEPCo’s future revenues by approximately $15 million on an annual basis.
2016 Texas Base Rate Case
In 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% ROE. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50 million based upon a ROE of 9.6%, effective May 2017. The final order also included: (a) approval to recover the Texas jurisdictional share of environmental investments placed in-service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1 and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c) approval of $2 million in additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission cost recovery mechanism.
As a result of the final order, in 2017 SWEPCo: (a) recorded an impairment charge of $19 million, which included $7 million associated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments, (b) recognized $32 million of additional revenues, for the period of May 2017 through December 2017, that was surcharged to customers in 2018 and (c) recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offset by the deferral of rate case expense. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017 revenues was
collected during 2018. In March 2018, the PUCT clarified and corrected portions of the final order, without changing the overall decision or amounts of the rate change. The order has been appealed by various intervenors. 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.
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 September 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $92 million ($89 million of which has been deferred as a regulatory asset related to the Louisiana jurisdiction) and incremental capital expenditures of $18 million, all of which is related to the Louisiana jurisdiction. In October 2021, SWEPCo requested recovery of these storm costs, in addition to Hurricane Delta and February 2021 winter storm costs, in a filing with the LPSC. See “Storm Restoration Costs” above for more information. 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 September 30, 2021, management estimates that SWEPCo has incurred incremental other operation and maintenance expenses of $18 million, which has been deferred as a regulatory asset. Also, management estimates that SWEPCo has incurred incremental capital expenditures of $2 million. In October 2021, SWEPCo requested recovery of these storm costs, in addition to Hurricane Laura and February 2021 winter storm costs, in a filing with the LPSC. See “Storm Restoration Costs” above for more information. 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. SWEPCo subsequently filed a request with the PUCT lowering the requested annual increase in Texas base rates to $100 million which would result in an $85 million net annual base rate increase after moving the proposed riders to rate base.
In August 2021, an ALJJanuary 2022, the PUCT issued a Proposal for Decision (PFD) which would provide SWEPCo withfinal order approving an annual revenue increase of $41$39 million based upon a 9.45%9.25% ROE. The PFDorder also includes: (a) rates implemented retroactively back to March 18, 2021, (b) $5 million of the proposed increase related to vegetation management, (c) a denial of the requested $2 million annually to establish a storm catastrophe reserve and (d) the creation of a rider that would recover the Dolet Hills Power Station as if it were in rate base until its retirement at the end of 2021 and starting in 2022 the remaining net book value would be recovered as a regulatory asset through 2046. AnAs a result of the final order, fromSWEPCo recorded a disallowance of $12 million in 2021 associated with the lack of return on the Dolet Hills Power Station. In February 2022, SWEPCo filed a motion for rehearing with the PUCT is expectedchallenging several errors in the fourth quarterorder, which include challenges of 2021. If anythe approved ROE, the denial of thesea reasonable return or carrying costs are not recoverable, it could reduce future net incomeon the Dolet Hills Power Station and cash flows and impact financial condition.the calculation of the Texas jurisdictional share of the storm catastrophe reserve. In April 2022, the PUCT denied the motion for rehearing. In May 2022, SWEPCo filed a petition for review with the Texas District Court seeking a judicial review of the several errors challenged in the PUCT’s final order.
2020 Louisiana Base Rate Case
In December 2020, SWEPCo filed a request with the LPSC for a $134 million annual increase in Louisiana base rates based upon a proposed 10.35% ROE. In March 2021, SWEPCo filed asubsequently revised request with the LPSCrequested annual increase to remove$114 million to reflect removing hurricane storm restoration costs from the base rate case filing and seek recovery of thosefiling. The hurricane costs have been requested in a separate storm filing. SWEPCo’s revisedSee “2021 Louisiana Storm Cost Filing” below for more information. The base case 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 SWEPCo’s request to remove the hurricane storm costs from the base rate case filing. In October 2021, SWEPCo requested recovery of the $152 million of storm costs associated with Hurricanes Delta, Laura and the February 2021 winter storm in a filing with the LPSC. See “Storm Restoration Costs” above for more information.
In July 2021, the LPSC staff filed testimony supporting a $6 million annual increase in base rates based upon ana ROE of 9.1% while other intervenors recommended ana 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. In August 2022, in a separate proceeding, the LPSC staff recommended recovery of, but no return on, the Dolet Hills Power Station based on a five-year recovery period if the remaining net book value is not recovered utilizing securitization. Additionally, the LPSC staff recommended that the remaining net book value be reduced for depreciation expenses, and operation and maintenance costs in rates since the plant was retired in December 2021.
In September 2021, SWEPCo filed rebuttal testimony supporting a revised requested annual increase in base rates of $95 million. The primary differences in the rebuttal testimony from the previous revised request of $114 million are modifications to the proposed recovery of the Dolet Hills Power Station and revisions to various proposed
amortizations. LPSC staff and intervenor responses to SWEPCo’s rebuttal testimony were filed in October 2021. The procedural schedule for the case is on hold due to ongoing settlement discussions.
If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2021 Arkansas Base Rate Case
In July 2021, SWEPCo filed a request with the APSC for an $85 million annual increase in Arkansas base rates based upon a proposed 10.35% ROE.ROE with a capital structure of 48.7% debt and 51.3% common equity. The proposed annual increase includes: (a) a $41 million revenue requirement for the North Central Wind Facilities, (b) a $14 million annual depreciation increase primarily due to recovery of the Dolet Hills Power Station through 2026 and Pirkey Plant and Welsh Plant, Units 1 and 3 through 2037 and (c) a $6 million increase due to SPP costs. In January 2022, SWEPCo requestsfiled testimony revising the requested annual increase in Arkansas base rates to $81 million. SWEPCo requested that rates arebecome effective beginning in June 2022. Staff and intervenor testimony is expected in December 2021.
In May 2022, the APSC issued a final order approving an annual revenue increase of $49 million based upon a 9.5% ROE. The order also includes: (a) a capital structure of 55% debt and 45% common equity, (b) approval to recover the Dolet Hills Power Station as a regulatory asset over five years without a return on this investment resulting in an immaterial disallowance in the second quarter of 2022, (c) the denial of accelerated depreciation for the Pirkey Plant and Welsh Plant, Units 1 and 3 and (d) approval of a rider to recover SPP costs and revenues. The final order also denied the inclusion of the stand-alone NOLC in SWEPCo’s deferred tax assets, but included approval of the deferral of the forgone revenue requirement associated with the NOLC and excess NOLC, with recovery of the deferral contingent upon receipt of a supportive private letter ruling from the IRS. Rates were implemented with the first billing cycle of July 2022.
2021 Louisiana Storm Cost Filing
In 2020, Hurricanes Laura and Delta caused power outages and extensive damage to the SWEPCo service territories, primarily impacting the Louisiana jurisdiction. Following both hurricanes, the LPSC issued orders allowing Louisiana utilities, including SWEPCo, to establish regulatory assets to track and defer expenses associated with these storms. In February 2021, severe winter weather impacted the Louisiana jurisdiction and in March 2021, the LPSC approved the deferral of incremental storm restoration expenses related to the winter storm. In October 2021, SWEPCo filed a request with the LPSC for recovery of $145 million in deferred storm costs associated with the three storms. As part of the filing, SWEPCo requested recovery of the carrying charges on the deferred regulatory asset at a weighted average cost of capital through a rider beginning in January 2022. In May 2022, LPSC staff testimony was submitted to the LPSC. In July 2022, SWEPCo filed rebuttal testimony which agreed to make a request for securitization as the LPSC staff had recommended in their testimony. An order is expected before the end of 2022. If any of thesethe storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
February 2021 Severe Winter Weather Impacts in SPP
As discussed in the “PSO Rate Matters” section above, severe winter weather had a significant impact in SPP, resulting in significantly increased market prices for natural gas power plants to meet reliability needs for the SPP electric system. For the time period of February 9, 2021, to February 20, 2021, SWEPCo’s natural gas expenses and purchases of electricity still to be recovered from customers are $349 million as of September 30, 2022, of which $85 million, $126 million and $138 million is related to the Arkansas, Louisiana and Texas jurisdictions, respectively.
In March 2021, the APSC issued an order authorizing recovery of the Arkansas jurisdictional share of the retail customer fuel costs over five years, with the appropriate carrying charge to be determined at a later date. Subsequently, SWEPCo began recovery of these fuel costs. In April 2021, SWEPCo filed testimony supporting a
five-year recovery with a carrying charge of 6.05%. In June 2022, the APSC ordered SWEPCo to recover the Arkansas jurisdictional share of the fuel costs over six years with a carrying charge equal to its weighted average cost of capital, subject to a prudency review and true-up.
In March 2021, the LPSC approved a special order granting a temporary modification to the FAC and shortly after SWEPCo began recovery of its Louisiana jurisdictional share of these fuel costs based on a five-year recovery period inclusive of an interim carrying charge of 3.25%. SWEPCo will work with the LPSC to finalize the actual recovery period and determine the appropriate carrying charge in future proceedings.
In August 2021, SWEPCo filed an application with the PUCT to implement a net interim fuel surcharge for the Texas jurisdictional share of these retail fuel costs. The application requested a five-year recovery with a carrying charge of 7.18%. In March 2022, the PUCT ordered SWEPCo to recover the Texas jurisdictional share of the fuel costs over five years with a carrying charge of 1.65% and ordered SWEPCo to file a fuel reconciliation addressing fuel costs from January 1, 2020 through December 31, 2021.
If SWEPCo is unable to recover any of the costs relating to the extraordinary fuel and purchases of electricity, or obtain authorization of a reasonable carrying charge on these costs, it could reduce future net income and cash flows and impact financial condition.
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 has reviewedIn March 2022, the FERC issued an order on the formal challenge which ruled in favor of the joint customers on several issues. Management has determined that the result of the order will have an immaterial impact to the financial statements of AEP, AEPTCo, PSO and responses were filed with 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.SWEPCo.
Independence Energy Connection Project (Applies to AEP)
In 2016, PJM approved the Independence Energy Connection Project (IEC) and included it in its Regional Transmission Expansion Plan to alleviate congestion. Transource Energy ownshas an ownership interest in the IEC, which is located in Maryland and Pennsylvania. In June 2020, the Maryland Public Service Commission approved a Certificate of Public Convenience and Necessity to construct the portion of the IEC in Maryland. In May 2021, the Pennsylvania Public Utility Commission (PA PUC)(PAPUC) denied the IEC certificate for siting and construction of the portion in Pennsylvania. Transource Energy has appealed the PA PUCPAPUC ruling in Pennsylvania state court and challenged the ruling before the United States District Court for the Middle District of Pennsylvania. The case beforeIn May 2022, the Pennsylvania state court is pendingissued an order affirming the PAPUC decision. The PAPUC decision remains subject to the jurisdiction and the case beforereview of the United States District Court for the Middle District of Pennsylvania, is on hold, pending the outcomewhich had stayed review of the case inPAPUC decision until the Pennsylvania state court.court had ordered. The procedural schedule for this case states that a decision by the United States District Court for the Middle of Pennsylvania will not be reached until 2023.
In September 2021, PJM notified Transource Energy that the IEC was suspended to allow for the regulatory and related appeals process to proceed in an orderly manner without breaching milestone dates in the project agreement. At that time, PJM stated that the IEC has not been cancelled and remains necessary to alleviate congestion. PJM will reevaluatecontinues to evaluate reliability and market efficiency in the need for the IEC at the end of 2021 during its annual reevaluation process.area. As of September 30, 2021,2022, AEP’s share of IEC capital expenditures was approximately $79 million.$83 million, located in Total Property, Plant and Equipment - Net on AEP’s balance sheets. The FERC has previously granted abandonment benefits for this project, allowing the full recovery of prudently incurred costs if the project is cancelled for reasons outside the control of Transource Energy. If any of the IEC costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC RTO Incentive Complaint (Applies to AEP, AEPTCo and OPCo)
In February 2022, the Office of the Ohio Consumers’ Counsel filed a complaint against AEPSC, American Transmission Systems, Inc. and Duke Energy Ohio, alleging the 50 basis point RTO incentive included in Ohio Transmission Owners’ respective transmission formula rates is not just and reasonable and therefore should be eliminated on the basis that RTO participation is not voluntary, but rather is required by Ohio law. In March 2022, AEPSC filed a motion to dismiss the Ohio Consumers’ Counsel’s February 2022 complaint with the FERC on the basis of certain deficiencies, including that the complaint fails to request relief that can be granted under FERC regulations because AEPSC is not a public utility nor does it have a transmission rate on file with the FERC. Management believes its financial statements adequately address the impact of the February 2022 complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.
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 20202021 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 20262027 and 2023,2024, respectively, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of September 30, 2021,2022, 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 five uncommitted facilities totaling $375$400 million. The Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities as of September 30, 20212022 were as follows:
| | | | | | | | | | | | | | |
Company | | Amount | | Maturity |
| | (in millions) | | |
AEP | | $ | 179.5309.9 | | | October 20212022 to August 20222023 |
AEP Texas | | 2.21.8 | | | July 20222023 |
| | | | |
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 September 30, 2021,2022, the maximum potential amount of future payments associated with these guarantees was $148$120 million, with the last
guarantee expiring in December 2037. The non-contingent liability recorded associated with these guarantees was $29$5 million, with an additional $2 million$395 thousand expected credit loss liability for the contingent portion of the guarantees. In accordance with the accounting guidance for guarantees, the initial recognition of the non-contingent liabilities increased AEP’s carrying values of the respective equity method investees. 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 September 30, 2021,2022, 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 September 30, 2021,2022, 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 | | $ | 47.845.9 | |
AEP Texas | | 11.110.9 | |
APCo | | 6.26.3 | |
I&M | | 4.14.3 | |
OPCo | | 7.67.4 | |
PSO | | 4.74.8 | |
SWEPCo | | 5.25.4 | |
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).2. The Owner Trustee wastrusts were 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 thetrusts own undivided interests in Rockport Plant, Unit 2 and leases equal portions to AEGCo and I&M. The lease is accounted for asIn April 2021, AEGCo and I&M executed an operating lease. The lease term is for 33 years andagreement to purchase 100% of the interests in the Rockport Plant, Unit 2 effective at the end of the lease term in December 2022. In December 2021, AEGCo and I&M havesatisfied the optionnecessary regulatory approvals to renewcomplete the acquisition. Upon receipt of the regulatory approval, the addition of the lessee forward purchase obligation resulted in the modified 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,changing classification from operating to finance for AEGCo and I&M have no ownership interest in the Owner
Trustee and do not guarantee its debt.&M. The future minimum lease payments for this sale-and-leaseback transaction as of September 30, 20212022, inclusive of the purchase obligation, 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 | |
| | | | | | | | | | | | | | |
Future Minimum Lease Payments | | AEP (a) | | I&M |
| | (in millions) |
| | | | |
2022 | | $ | 174.9 | | | $ | 87.4 | |
Total Future Minimum Lease Payments | | $ | 174.9 | | | $ | 87.4 | |
(a)AEP’s future minimum lease payments include equal shares from AEGCo and I&M.
The lease modification also created variable interests in the trusts that own the undivided interests in Rockport Plant, Unit 2 for AEGCo and I&M. Neither AEGCo nor I&M are the primary beneficiaries of the trusts because AEGCo nor I&M has the power to direct the most significant activities of the trusts. AEP and I&M’s maximum exposure to loss associated with the trust is equal to the total future minimum lease payments, inclusive of the purchase obligation, as shown in the table above.
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 September 30, 2021,2022, the maximum potential amount of future payments required under the guaranteed leases was $43$36 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 September 30, 2021,2022, AEP’s boat and barge lease guarantee liability was $2 million, of which $1 million was recorded in Other Current Liabilities and $1 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.
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 suit in the U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it would be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering, refueling or retirement of the unit. The plaintiffs sought a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs.
After the litigation proceeded at the District Courtdistrict court and Circuit Court levels, onappellate court, in April 20, 2021, I&M and AEGCo reached an agreement to acquire 100% of the interests in Rockport Plant, Unit 2 for $115.5$116 million from certain financial institutions that own the unit through trusts established by Wilmington Trust, the nonaffiliated owner trustee of the ownership interests in the unit, with closing to occur as of the end of the Rockport Plant, Unit 2 lease in December 2022. 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. 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 required regulatory approvals at the IURC and FERC have been obtained that would allow the closing to occur as of the end of the lease in December 2022. Management believes its financial statements appropriately reflect the resolution of the litigation.
Upon the end of the Rockport Unit 2 lease in December 2022, AEGCo’s 50% ownership share of Rockport Unit 2 will be billed 100% to I&M under a FERC-approved unit power agreement. In addition, upon the end of the Rockport Unit 2 lease, I&M’s 50% ownership share of Rockport Unit 2 and I&M’s purchased power from AEGCo related to Rockport Unit 2 will be a merchant resource for I&M until Rockport Unit 2 is retired. A 2021 IURC order approved a settlement agreement addressing the future use of Rockport Unit 2 as a short-term capacity resource through the June 2023 - May 2024 PJM planning year. I&M has a similar proposal pending before the MPSC in I&M’s 2022 Michigan Integrated Resource Plan (IRP) filing. If I&M cannot recover its future investment and expenses related to the merchant share of Rockport Unit 2, it could reduce future net income and cash flows and impact financial condition.
Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula
Four participants in The American Electric Power System Retirement Plan (the Plan) has receivedfiled a letter written on behalfclass action complaint in December 2021 in the U.S. District Court for the Southern District of four participants (the Claimants) making a claim for additional plan benefitsOhio against AEPSC and purporting to advance such claims on behalf of a class.the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Claimants have assertedplaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) the companyAEP failed to provide required notice regarding the changes to the Plan. AEP has respondedAmong other relief, the Complaint seeks reformation of the Plan 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 Committeeprovide additional benefits and the Committee upheldrecovery of plan benefits for former employees under such reformed plan. The plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the denial of claims. ManagementPlan filed a motion to dismiss the complaint for failure to state a claim. On August 16, 2022, the district court granted the motion to dismiss the complaint without prejudice. The plaintiffs have filed a motion for leave to file an amended complaint. AEP 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,AEP, with assistance from outside advisors, conducted a review of the circumstances surrounding the passage of the bill. We doManagement does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.
In August 2020, an AEP shareholder filed a putative class action lawsuit in the 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 allegesalleged 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 seekssought monetary damages, among other forms of relief. On May 10,In December 2021, the defendants filed a motion to dismissdistrict court issued an opinion and order dismissing the securities litigation for failurecomplaint with prejudice, determining that the complaint failed to state a claim andplead any actionable misrepresentations or omissions. The plaintiffs did not appeal the motion was fully briefed as of July 26, 2021. The Court has scheduled oral argument for November 23, 2021 on the motion to dismiss. 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.ruling.
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 threecourt entered a scheduling order in the New York state court derivative action staying the case other than with respect to briefing the motion to dismiss. AEP filed its motion to dismiss on April 29, 2022. On September 13, 2022, the New York state court granted the motion to dismiss with prejudice and plaintiffs have filed a notice of appeal with the New York appellate court. The two derivative actions pending in federal district court in Ohio have been consolidated
and the plaintiffs in the consolidated action filed an amended complaint.AEP filed a motion to dismiss on May 3, 2022 and briefing on the motion to dismiss has been completed. Discovery remains stayed pending the district court’s ruling on the motion to dismiss. The plaintiff in the Ohio state court case advised that they no longer agreed to stay the proceedings, therefore, AEP filed a motion to continue the stays of proceedings on May 20, 2022 and the plaintiff filed an amended complaint on June 2, 2022. On June 15, 2022, the Ohio state court entered an order continuing the stays of that case until the resolution of the motion to dismiss the securities litigation.consolidated derivative actions pending in Ohio federal district court. The fourth has been stayed until such time as the court determines to lift the stay. The companydefendants will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.
OnIn 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 CompanyAEP 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 ofsince withdrawn the litigation demand, until the resolutionwhich is now terminated and 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.no further effect.
In May 2021, AEP received a subpoena from the SEC’s Division of Enforcement seeking various documents, including documents relating to the benefits to AEP from the passage of HB 6 and documents relating to AEP’s policies and financial processes and controls. In August 2022, AEP received a second subpoena from the SEC seeking various additional documents relating to its ongoing inquiry. AEP is cooperating fully with the SEC’s subpoena.investigation. Although the outcome of the SEC’s investigation cannot be predicted, management does not believe the results of this inquiry will have a material impact on our financial condition, results of operations or cash flows.
6. ACQUISITIONS, ASSETS AND LIABILITIES HELD FOR SALE, DISPOSITIONS AND IMPAIRMENTS
The disclosures in this note apply to AEP unless indicated otherwise.
ACQUISITIONS
Dry Lake Solar Project (Generation & Marketing Segment) (Applies to AEP)
In November 2020, AEP signed a Purchase and Sale Agreement with a nonaffiliate to acquire a 75% interest in the entity that owns the 100 MW Dry Lake Solar Project (Dry(collectively referred to as 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 $16 million. As of September 30, 2021,2022, AEP recognized approximately $146$143 million of Property, Plant and Equipment and approximately $35$34 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 NCWF, comprised of three Oklahoma wind facilities totaling 1,4851,484 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(998 MW), Maverick (287 MW) and Sundance (199 MW). Output from the NCWF will serveserves 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. Recovery of the Arkansas portion of the NCWF revenue requirement is requestedthrough base rates was approved by the APSC in SWEPCo’s pending 2021 Arkansas Base Rate Case.May 2022. 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.
In September 2021, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Maverick during its development and construction for $383 million, the second of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the
Maverick assets in proportion to their undivided ownership interests. Maverick was placed in-service in September 2021.
In March 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction for $1.2 billion, the third of the three NCWF acquisitions. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to their undivided ownership interests. Traverse was placed in-service in March 2022.
In accordance with the guidance for “Business Combinations,” management determined that the acquisitions of Sundance and Maverickthe NCWF projects represent asset acquisitions. As of September 30, 2021,2022, PSO and SWEPCo had approximately $314$894 million and $376 million,$1.1 billion, of gross Property, Plant and Equipment on the balance sheets, respectively, related to the Sundance and Maverick NCWF projects. 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 and Maverick.the NCWF projects.
The respective Purchase and Sale Agreement (PSA) includes collectiveAgreements (PSAs) include 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, Maverick and MaverickTraverse were built upon. TheseThe lessee interests as lessee in each of the land contracts were transferred to Sundance, Maverick and MaverickTraverse (and subsequently to PSO and SWEPCo) as a part of the closingclosings of the PSA. Asrespective PSAs. The current Obligations Under Operating Leases related to the NCWF projects were immaterial as of September 30, 2022 and December 31, 2021 for PSO and SWEPCo. See the Noncurrenttable below for the noncurrent Obligations Under Operating Leases for Sundance are $13the NCWF projects for PSO and SWEPCo:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | PSO | | SWEPCo |
| | September 30, 2022 | | December 31, 2021 | | September 30, 2022 | | December 31, 2021 |
| | (in millions) |
Project | | | | | | | | |
Sundance | | $ | 12.6 | | | $ | 12.6 | | | $ | 15.0 | | | $ | 15.1 | |
Maverick | | 18.0 | | | 18.0 | | | 21.6 | | | 21.6 | |
Traverse | | 39.7 | | | — | | | 47.7 | | | — | |
Total | | $ | 70.3 | | | $ | 30.6 | | | $ | 84.3 | | | $ | 36.7 | |
ASSETS AND LIABILITIES HELD FOR SALE
Disposition of KPCo and KTCo (Vertically Integrated Utilities and AEP Transmission Holdco Segments) (Applies to AEP and AEPTCo)
In October 2021, AEP entered into a Stock Purchase Agreement (SPA) to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to certain conditions contingent upon the closing of the sale. AEP has received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the Committee on Foreign Investment in the United States. The sale remains subject to FERC approval under Section 203 of the Federal Power Act.
In September 2022, AEP, AEPTCo and Liberty entered into an amendment (Amendment) to the SPA which reduced the purchase price to approximately $2.646 billion and Liberty agreed to waive, upon FERC approval of the sale, the SPA condition precedent to closing requiring the issuance of regulatory orders approving a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo. The Amendment also provided that the closing shall not occur prior to January 4, 2023, unless mutually agreed to by AEP and Liberty.
Mitchell Plant Operations and Maintenance Agreement and Ownership Agreement
KPCo and WPCo each own a 50% undivided interest in the 1,560 MW coal-fired Mitchell Plant. As of September 30, 2022, the net book value of KPCo’s share of the Mitchell Plant, before cost of removal including CWIP and inventory, was $576 million.
In November 2021, AEP made filings with the KPSC, WVPSC and FERC seeking approval of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement. In February 2022, AEP filed a motion to withdraw its filing with the FERC. The KPSC and WVPSC issued orders addressing AEP’s filings in May 2022 and July 2022. Those orders proposed materially different modifications to the Mitchell Plant agreements filed by AEP such that the new agreements could not be executed by the parties. In lieu of new agreements, in July 2022, KPCo and WPCo confirmed with the KPSC and WVPSC, respectively, that they will continue operating under the existing Mitchell Agreement, utilizing the Mitchell Agreement Operating Committee’s authority under that agreement to issue appropriate resolutions so the parties can operate in accordance with each state commission’s directives related to CCR and ELG investment. In September 2022, pursuant to resolutions under the existing Mitchell Plant agreement, WPCo replaced KPCo as the Operator of Mitchell Plant.
Transfer of Ownership
FERC Proceedings
In December 2021, Liberty, KPCo and KTCo requested FERC approval of the sale under Section 203 of the Federal Power Act. In February 2022, several intervenors in the case filed protests related to whether the sale will negatively impact the wholesale transmission rates of applicants. In April 2022, the FERC issued a deficiency letter stating that the Section 203 application is deficient and that additional information is required to process it. In May 2022, Liberty, KPCo and KTCo supplemented the application and in June 2022, the FERC issued an order formally notifying AEP that it was exercising its ability to take up to an additional 180 days to act on the application. An order from the FERC is expected in the fourth quarter of 2022.
KPSC Proceedings
In May 2022, the KPSC approved the transfer of KPCo to Liberty subject to conditions contingent upon the closing of the sale, including establishment of regulatory liabilities to subsidize retail customer transmission and distribution expenses, a fuel adjustment clause bill credit, and a three-year Big Sandy decommissioning rider rate holiday during which KPCo’s carrying charge is reduced by 50%. As a result of the conditions imposed by KPSC, in the second quarter of 2022, AEP recorded a $69 million loss on the expected sale of the Kentucky Operations in accordance with accounting guidance for Fair Value Measurement.
Further, as a result of the Amendment and $15the change to the anticipated timing of the completion of the transaction, AEP recorded an additional $194 million pretax loss ($149 million net of tax) on the expected sale of the Kentucky Operations in the third quarter of 2022 in accordance with the accounting guidance for Fair Value Measurement. AEP recorded a $263 million pretax loss ($218 million net of tax) on the expected sale of the Kentucky Operations for the nine months ended September 30, 2022. AEP expects cash proceeds, net of taxes and transaction fees, from the sale of approximately $1.2 billion.
Subject to receipt of FERC authorization under Section 203 of the Federal Power Act, the sale is expected to close in January 2023 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction. AEP plans to use the proceeds from the sale to fund its continued investment in regulated businesses, including transmission and regulated renewables projects. If additional reductions in the fair value of the Kentucky Operations occur, it would reduce future net income and cash flows.
The Income Before Income Tax Expense (Benefit) of KPCo and KTCo were not material to AEP and AEPTCo on their respective statements of income for the three and nine months ended September 30, 2022 and 2021.
The major classes of KPCo and KTCo’s assets and liabilities presented in Assets Held for Sale and Liabilities Held for Sale on the balance sheets for PSO and SWEPCo, respectively, and the Noncurrent Obligations Under Operating Leases for Maverick are $18 million and $22 million on the balance sheets for PSO and SWEPCo, respectively.
Desert Sky Wind Farm and Trent Wind Farm (Generation & Marketing Segment)
In August 2020, AEP exercised its call right which required the nonaffiliated member of Desert Sky Wind Farm LLC and Trent Wind Farm LLC (collectively the LLCs) to sell its noncontrolling interest to AEP. The exercise price for the call right was determined using a discounted cash flow model with agreed input assumptions as well as updates to certain assumptions reasonably expected based on the actual results of the LLCs. As a result, the LLCs are wholly-owned by AEP and management has concluded thatAEPTCo are shown in the LLCs are no longer VIEs. AEP paid $57 million in cash, derecognized $63 million of Redeemable Noncontrolling Interest within Mezzanine Equity and recorded an increase of $6 million of Paid-In Capital on the balance sheets.table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | AEP | | AEPTCo |
| | September 30, 2022 | | December 31, 2021 | | September 30, 2022 | | December 31, 2021 |
| | (in millions) |
ASSETS | | | | | | | | |
Accounts Receivable and Accrued Unbilled Revenues | | $ | 77.8 | | | $ | 33.2 | | | $ | 1.7 | | | $ | 1.5 | |
Fuel, Materials and Supplies | | 36.7 | | | 30.6 | | | — | | | — | |
Property, Plant and Equipment, Net | | 2,387.4 | | | 2,302.7 | | | 167.0 | | | 165.3 | |
Regulatory Assets | | 508.6 | | | 484.7 | | | — | | | — | |
Other Classes of Assets that are not Major | | 38.1 | | | 68.5 | | | 5.0 | | | 1.1 | |
Total Major Classes of Assets Held for Sale | | 3,048.6 | | | 2,919.7 | | | 173.7 | | | 167.9 | |
Loss on the Expected Sale of Kentucky Operations (net of $45 million of Income Taxes) | | (218.0) | | | — | | | — | | | — | |
Assets Held for Sale | | $ | 2,830.6 | | | $ | 2,919.7 | | | $ | 173.7 | | | $ | 167.9 | |
| | | | | | | | |
LIABILITIES | | | | | | | | |
Accounts Payable | | $ | 62.4 | | | $ | 53.4 | | | $ | 0.7 | | | $ | 1.1 | |
Long-term Debt Due Within One Year | | 215.0 | | | 200.0 | | | — | | | — | |
Customer Deposits | | 38.0 | | | 32.4 | | | — | | | — | |
Deferred Income Taxes | | 497.8 | | | 441.6 | | | 16.4 | | | 15.4 | |
Long-term Debt | | 963.4 | | | 903.1 | | | — | | | — | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 138.1 | | | 148.1 | | | 8.0 | | | 7.6 | |
Other Classes of Liabilities that are not Major | | 77.3 | | | 102.3 | | | 2.5 | | | 3.5 | |
Liabilities Held for Sale | | $ | 1,992.0 | | | $ | 1,880.9 | | | $ | 27.6 | | | $ | 27.6 | |
DISPOSITIONS
ConesvilleDisposition of Cardinal Plant (Generation & Marketing Segment) (Applies to AEP)
In March 2022, AGR entered into an Asset Purchase agreement with a nonaffiliated electric cooperative to sell Cardinal Plant, Unit 1, a competitive generation asset totaling 595 MWs. The FERC approved the sale in May 2022 and the sale closed in the third quarter of 2022. The proceeds from the sale were not material. Concurrent with the closing of the sale, AGR executed a PPA with the nonaffiliated electric cooperative for rights to Unit 1’s power and capacity through 2028. AGR also retained certain obligations related to environmental remediation.
Subsequent to the closing of the sale, AGR continues to recognize Cardinal Plant, Unit 1 on its balance sheet due to continuing involvement through the PPA. As of September 30, 2022, the net book value of Cardinal Plant, Unit 1 was not material.
Disposition of Mineral Rights (Generation & Marketing Segment) (Applies to AEP)
In June 2020,2022, AEP andclosed on the sale of certain mineral rights to a nonaffiliated joint-owner executedthird-party and received $120 million of proceeds. The sale resulted in a pretax gain of $116 million in the second quarter of 2022.
IMPAIRMENTS
Flat Ridge 2 Wind LLC (Generation & Marketing Segment) (Applies to AEP)
In April 2019, AEP acquired Sempra Renewables LLC and its ownership interests in 724 MWs of wind generation and battery assets. The acquisition included a 50% ownership interest in five non-consolidated joint ventures, including Flat Ridge 2 Wind LLC (Flat Ridge 2), and two tax equity partnerships. The five non-consolidated joint ventures are jointly owned and operated by BP Wind Energy. Flat Ridge 2 sells electricity to three counterparties through long-term PPAs.
Regarding AEP’s investment in Flat Ridge 2, in June 2022, as a result of deteriorating financial performance, sale negotiations and AEP’s ongoing evaluation and ultimate decision to exit the investment in the near term, AEP determined a decline in the fair value of AEP’s investment in Flat Ridge 2 was other than temporary and recorded a pretax other than temporary impairment charge of $186 million in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. In the third quarter of 2022, in accordance with the accounting guidance for “Investments - Equity Method and Joint Ventures”, AEP recorded an Environmental Liabilityadditional $2 million pretax other than temporary impairment charge in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. AEP has recorded a $188 million other than temporary impairment in its investment in Flat Ridge 2 for the nine months ended September 30, 2022 in Equity Earnings (Losses) of Unconsolidated Subsidiaries on AEP’s Statement of Income. AEP’s determination of fair value utilized the accounting guidance for Fair Value Measurement market approach to valuation and Property Transferwas based on Level 2 pricing information from a third-party market participant. In September 2022, AEP signed a Purchase and Asset PurchaseSale Agreement with a nonaffiliated third-party relatednonaffiliate for AEP’s interest in Flat Ridge 2, subject to FERC approval. Management expects the merchant Conesville Plant site. The purchaser took ownershiptransaction to close in the fourth quarter of the assets2022 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 recordedhave an immaterial gainimpact on the transaction which is recordedfinancial statements. The carrying value of AEP’s investment in Other Operation on the statementsFlat Ridge 2 was not material to AEP as of income. AEP paid approximately $26 million at closing in June 2020 and made additional payments totaling $38 million in quarterly installments from October 2020 to July 2021. AEP will make additional payments totaling $34 million in quarterly installments from October 2021 to JulySeptember 30, 2022.
7. BENEFIT PLANS
The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise.AEPTCo.
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 | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 32.3 | | | $ | 28.0 | | | $ | 2.4 | | | $ | 2.5 | | Service Cost | $ | 30.7 | | | $ | 32.3 | | | $ | 1.8 | | | $ | 2.4 | |
Interest Cost | Interest Cost | 34.3 | | | 42.0 | | | 7.7 | | | 10.0 | | Interest Cost | 37.1 | | | 34.3 | | | 7.3 | | | 7.7 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (57.4) | | | (66.3) | | | (22.8) | | | (23.9) | | Expected Return on Plan Assets | (63.4) | | | (57.4) | | | (27.5) | | | (22.8) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (17.8) | | | (17.4) | | Amortization of Prior Service Credit | — | | | — | | | (17.9) | | | (17.8) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 25.3 | | | 23.5 | | | — | | | 1.4 | | Amortization of Net Actuarial Loss | 15.8 | | | 25.3 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 34.5 | | | $ | 27.2 | | | $ | (30.5) | | | $ | (27.4) | | Net Periodic Benefit Cost (Credit) | $ | 20.2 | | | $ | 34.5 | | | $ | (36.3) | | | $ | (30.5) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 96.9 | | | $ | 84.0 | | | $ | 7.2 | | | $ | 7.5 | | Service Cost | $ | 92.3 | | | $ | 96.9 | | | $ | 5.5 | | | $ | 7.2 | |
Interest Cost | Interest Cost | 102.9 | | | 125.9 | | | 22.9 | | | 29.9 | | Interest Cost | 111.2 | | | 102.9 | | | 21.9 | | | 22.9 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (172.3) | | | (198.7) | | | (68.4) | | | (71.8) | | Expected Return on Plan Assets | (190.1) | | | (172.3) | | | (82.5) | | | (68.4) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (53.2) | | | (52.3) | | Amortization of Prior Service Credit | — | | | — | | | (53.6) | | | (53.2) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 76.1 | | | 70.3 | | | — | | | 4.4 | | Amortization of Net Actuarial Loss | 47.3 | | | 76.1 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 103.6 | | | $ | 81.5 | | | $ | (91.5) | | | $ | (82.3) | | Net Periodic Benefit Cost (Credit) | $ | 60.7 | | | $ | 103.6 | | | $ | (108.7) | | | $ | (91.5) | |
AEP Texas
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 3.0 | | | $ | 2.6 | | | $ | 0.2 | | | $ | 0.2 | | Service Cost | $ | 2.8 | | | $ | 3.0 | | | $ | 0.1 | | | $ | 0.2 | |
Interest Cost | Interest Cost | 2.8 | | | 3.5 | | | 0.6 | | | 0.8 | | Interest Cost | 3.1 | | | 2.8 | | | 0.6 | | | 0.6 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (4.9) | | | (5.7) | | | (1.9) | | | (2.0) | | Expected Return on Plan Assets | (5.3) | | | (4.9) | | | (2.3) | | | (1.9) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (1.5) | | | (1.4) | | Amortization of Prior Service Credit | — | | | — | | | (1.5) | | | (1.5) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 2.1 | | | 1.9 | | | — | | | 0.1 | | Amortization of Net Actuarial Loss | 1.2 | | | 2.1 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 3.0 | | | $ | 2.3 | | | $ | (2.6) | | | $ | (2.3) | | Net Periodic Benefit Cost (Credit) | $ | 1.8 | | | $ | 3.0 | | | $ | (3.1) | | | $ | (2.6) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 8.9 | | | $ | 7.6 | | | $ | 0.5 | | | $ | 0.6 | | Service Cost | $ | 8.4 | | | $ | 8.9 | | | $ | 0.3 | | | $ | 0.5 | |
Interest Cost | Interest Cost | 8.4 | | | 10.5 | | | 1.8 | | | 2.4 | | Interest Cost | 9.1 | | | 8.4 | | | 1.7 | | | 1.8 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (14.6) | | | (17.1) | | | (5.6) | | | (6.0) | | Expected Return on Plan Assets | (15.8) | | | (14.6) | | | (6.8) | | | (5.6) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (4.5) | | | (4.4) | | Amortization of Prior Service Credit | — | | | — | | | (4.5) | | | (4.5) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 6.2 | | | 5.8 | | | — | | | 0.4 | | Amortization of Net Actuarial Loss | 3.8 | | | 6.2 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 8.9 | | | $ | 6.8 | | | $ | (7.8) | | | $ | (7.0) | | Net Periodic Benefit Cost (Credit) | $ | 5.5 | | | $ | 8.9 | | | $ | (9.3) | | | $ | (7.8) | |
APCo
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 3.0 | | | $ | 2.7 | | | $ | 0.3 | | | $ | 0.3 | | Service Cost | $ | 2.9 | | | $ | 3.0 | | | $ | 0.2 | | | $ | 0.3 | |
Interest Cost | Interest Cost | 4.1 | | | 5.0 | | | 1.3 | | | 1.6 | | Interest Cost | 4.3 | | | 4.1 | | | 1.2 | | | 1.3 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (7.3) | | | (8.4) | | | (3.4) | | | (3.6) | | Expected Return on Plan Assets | (8.1) | | | (7.3) | | | (4.1) | | | (3.4) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (2.6) | | | (2.5) | | Amortization of Prior Service Credit | — | | | — | | | (2.6) | | | (2.6) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 3.0 | | | 2.8 | | | — | | | 0.2 | | Amortization of Net Actuarial Loss | 1.9 | | | 3.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 2.8 | | | $ | 2.1 | | | $ | (4.4) | | | $ | (4.0) | | Net Periodic Benefit Cost (Credit) | $ | 1.0 | | | $ | 2.8 | | | $ | (5.3) | | | $ | (4.4) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 8.9 | | | $ | 7.9 | | | $ | 0.8 | | | $ | 0.8 | | Service Cost | $ | 8.6 | | | $ | 8.9 | | | $ | 0.6 | | | $ | 0.8 | |
Interest Cost | Interest Cost | 12.3 | | | 15.2 | | | 3.7 | | | 4.9 | | Interest Cost | 13.1 | | | 12.3 | | | 3.5 | | | 3.7 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (21.8) | | | (25.2) | | | (10.1) | | | (10.9) | | Expected Return on Plan Assets | (24.3) | | | (21.8) | | | (12.2) | | | (10.1) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (7.8) | | | (7.6) | | Amortization of Prior Service Credit | — | | | — | | | (7.8) | | | (7.8) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 9.0 | | | 8.4 | | | — | | | 0.7 | | Amortization of Net Actuarial Loss | 5.5 | | | 9.0 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 8.4 | | | $ | 6.3 | | | $ | (13.4) | | | $ | (12.1) | | Net Periodic Benefit Cost (Credit) | $ | 2.9 | | | $ | 8.4 | | | $ | (15.9) | | | $ | (13.4) | |
I&M
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 4.4 | | | $ | 3.9 | | | $ | 0.4 | | | $ | 0.4 | | Service Cost | $ | 4.0 | | | $ | 4.4 | | | $ | 0.2 | | | $ | 0.4 | |
Interest Cost | Interest Cost | 4.0 | | | 4.9 | | | 0.8 | | | 1.2 | | Interest Cost | 4.3 | | | 4.0 | | | 0.8 | | | 0.8 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (7.2) | | | (8.3) | | | (2.7) | | | (3.0) | | Expected Return on Plan Assets | (8.1) | | | (7.2) | | | (3.3) | | | (2.7) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (2.5) | | | (2.3) | | Amortization of Prior Service Credit | — | | | — | | | (2.4) | | | (2.5) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 2.9 | | | 2.7 | | | — | | | 0.1 | | Amortization of Net Actuarial Loss | 1.8 | | | 2.9 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 4.1 | | | $ | 3.2 | | | $ | (4.0) | | | $ | (3.6) | | Net Periodic Benefit Cost (Credit) | $ | 2.0 | | | $ | 4.1 | | | $ | (4.7) | | | $ | (4.0) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 13.1 | | | $ | 11.6 | | | $ | 1.0 | | | $ | 1.1 | | Service Cost | $ | 12.1 | | | $ | 13.1 | | | $ | 0.7 | | | $ | 1.0 | |
Interest Cost | Interest Cost | 12.1 | | | 14.7 | | | 2.6 | | | 3.5 | | Interest Cost | 12.7 | | | 12.1 | | | 2.5 | | | 2.6 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (21.6) | | | (24.9) | | | (8.3) | | | (8.8) | | Expected Return on Plan Assets | (24.2) | | | (21.6) | | | (10.2) | | | (8.3) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (7.3) | | | (7.1) | | Amortization of Prior Service Credit | — | | | — | | | (7.3) | | | (7.3) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 8.8 | | | 8.1 | | | — | | | 0.5 | | Amortization of Net Actuarial Loss | 5.3 | | | 8.8 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 12.4 | | | $ | 9.5 | | | $ | (12.0) | | | $ | (10.8) | | Net Periodic Benefit Cost (Credit) | $ | 5.9 | | | $ | 12.4 | | | $ | (14.3) | | | $ | (12.0) | |
OPCo
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 2.9 | | | $ | 2.4 | | | $ | 0.2 | | | $ | 0.2 | | Service Cost | $ | 2.8 | | | $ | 2.9 | | | $ | 0.2 | | | $ | 0.2 | |
Interest Cost | Interest Cost | 3.1 | | | 3.9 | | | 0.7 | | | 1.0 | | Interest Cost | 3.4 | | | 3.1 | | | 0.7 | | | 0.7 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (5.7) | | | (6.6) | | | (2.4) | | | (2.6) | | Expected Return on Plan Assets | (6.2) | | | (5.7) | | | (3.0) | | | (2.4) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (1.7) | | | (1.8) | | Amortization of Prior Service Credit | — | | | — | | | (1.8) | | | (1.7) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 2.3 | | | 2.1 | | | — | | | 0.2 | | Amortization of Net Actuarial Loss | 1.3 | | | 2.3 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 2.6 | | | $ | 1.8 | | | $ | (3.2) | | | $ | (3.0) | | Net Periodic Benefit Cost (Credit) | $ | 1.3 | | | $ | 2.6 | | | $ | (3.9) | | | $ | (3.2) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 8.6 | | | $ | 7.2 | | | $ | 0.6 | | | $ | 0.7 | | Service Cost | $ | 8.4 | | | $ | 8.6 | | | $ | 0.5 | | | $ | 0.6 | |
Interest Cost | Interest Cost | 9.3 | | | 11.6 | | | 2.3 | | | 3.1 | | Interest Cost | 10.0 | | | 9.3 | | | 2.2 | | | 2.3 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (16.8) | | | (19.7) | | | (7.3) | | | (7.9) | | Expected Return on Plan Assets | (18.6) | | | (16.8) | | | (8.9) | | | (7.3) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (5.3) | | | (5.3) | | Amortization of Prior Service Credit | — | | | — | | | (5.4) | | | (5.3) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 6.8 | | | 6.4 | | | — | | | 0.5 | | Amortization of Net Actuarial Loss | 4.1 | | | 6.8 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 7.9 | | | $ | 5.5 | | | $ | (9.7) | | | $ | (8.9) | | Net Periodic Benefit Cost (Credit) | $ | 3.9 | | | $ | 7.9 | | | $ | (11.6) | | | $ | (9.7) | |
PSO
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 2.0 | | | $ | 1.9 | | | $ | 0.1 | | | $ | 0.1 | | Service Cost | $ | 1.8 | | | $ | 2.0 | | | $ | 0.2 | | | $ | 0.1 | |
Interest Cost | Interest Cost | 1.7 | | | 2.1 | | | 0.4 | | | 0.6 | | Interest Cost | 1.8 | | | 1.7 | | | 0.4 | | | 0.4 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (3.0) | | | (3.6) | | | (1.3) | | | (1.3) | | Expected Return on Plan Assets | (3.3) | | | (3.0) | | | (1.6) | | | (1.3) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (1.1) | | | (1.0) | | Amortization of Prior Service Credit | — | | | — | | | (1.1) | | | (1.1) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 1.2 | | | 1.1 | | | — | | | — | | Amortization of Net Actuarial Loss | 0.7 | | | 1.2 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 1.9 | | | $ | 1.5 | | | $ | (1.9) | | | $ | (1.6) | | Net Periodic Benefit Cost (Credit) | $ | 1.0 | | | $ | 1.9 | | | $ | (2.1) | | | $ | (1.9) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 6.0 | | | $ | 5.5 | | | $ | 0.4 | | | $ | 0.4 | | Service Cost | $ | 5.5 | | | $ | 6.0 | | | $ | 0.4 | | | $ | 0.4 | |
Interest Cost | Interest Cost | 5.0 | | | 6.4 | | | 1.2 | | | 1.6 | | Interest Cost | 5.3 | | | 5.0 | | | 1.1 | | | 1.2 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (9.2) | | | (10.9) | | | (3.8) | | | (3.9) | | Expected Return on Plan Assets | (10.1) | | | (9.2) | | | (4.6) | | | (3.8) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (3.3) | | | (3.2) | | Amortization of Prior Service Credit | — | | | — | | | (3.3) | | | (3.3) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 3.7 | | | 3.5 | | | — | | | 0.2 | | Amortization of Net Actuarial Loss | 2.2 | | | 3.7 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 5.5 | | | $ | 4.5 | | | $ | (5.5) | | | $ | (4.9) | | Net Periodic Benefit Cost (Credit) | $ | 2.9 | | | $ | 5.5 | | | $ | (6.4) | | | $ | (5.5) | |
SWEPCo
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, | | Three Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 2.7 | | | $ | 2.6 | | | $ | 0.3 | | | $ | 0.2 | | Service Cost | $ | 2.7 | | | $ | 2.7 | | | $ | 0.1 | | | $ | 0.3 | |
Interest Cost | Interest Cost | 2.2 | | | 2.5 | | | 0.4 | | | 0.6 | | Interest Cost | 2.2 | | | 2.2 | | | 0.5 | | | 0.4 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (3.3) | | | (3.9) | | | (1.5) | | | (1.5) | | Expected Return on Plan Assets | (3.6) | | | (3.3) | | | (1.8) | | | (1.5) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (1.4) | | | (1.3) | | Amortization of Prior Service Credit | — | | | — | | | (1.4) | | | (1.4) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 1.5 | | | 1.4 | | | — | | | 0.1 | | Amortization of Net Actuarial Loss | 0.9 | | | 1.5 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 3.1 | | | $ | 2.6 | | | $ | (2.2) | | | $ | (1.9) | | Net Periodic Benefit Cost (Credit) | $ | 2.2 | | | $ | 3.1 | | | $ | (2.6) | | | $ | (2.2) | |
| | | Pension Plans | | OPEB | | Pension Plans | | OPEB |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Service Cost | Service Cost | $ | 8.4 | | | $ | 7.5 | | | $ | 0.6 | | | $ | 0.6 | | Service Cost | $ | 8.0 | | | $ | 8.4 | | | $ | 0.4 | | | $ | 0.6 | |
Interest Cost | Interest Cost | 6.4 | | | 7.6 | | | 1.4 | | | 1.9 | | Interest Cost | 6.8 | | | 6.4 | | | 1.4 | | | 1.4 | |
Expected Return on Plan Assets | Expected Return on Plan Assets | (10.1) | | | (11.7) | | | (4.5) | | | (4.7) | | Expected Return on Plan Assets | (10.9) | | | (10.1) | | | (5.5) | | | (4.5) | |
Amortization of Prior Service Credit | Amortization of Prior Service Credit | — | | | — | | | (4.0) | | | (3.9) | | Amortization of Prior Service Credit | — | | | — | | | (4.0) | | | (4.0) | |
Amortization of Net Actuarial Loss | Amortization of Net Actuarial Loss | 4.6 | | | 4.2 | | | — | | | 0.3 | | Amortization of Net Actuarial Loss | 2.8 | | | 4.6 | | | — | | | — | |
Net Periodic Benefit Cost (Credit) | Net Periodic Benefit Cost (Credit) | $ | 9.3 | | | $ | 7.6 | | | $ | (6.5) | | | $ | (5.8) | | Net Periodic Benefit Cost (Credit) | $ | 6.7 | | | $ | 9.3 | | | $ | (7.7) | | | $ | (6.5) | |
Qualified Pension Contribution (Applies to all Registrants except AEPTCo and PSO)
For the qualified pension plan, discretionary contributions may be made to maintain the funded status of the plan. In the third quarter of 2020, AEP made a discretionary contribution to the qualified pension plan. The following table provides details of the contribution by Registrant:
| | | | | | | | |
Company | | Qualified Pension Plan |
| | (in millions) |
AEP | | $ | 110.3 | |
AEP Texas | | 11.3 | |
APCo | | 7.0 | |
I&M | | 6.4 | |
OPCo | | 0.1 | |
| | |
SWEPCo | | 8.9 | |
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.
The tables below represent AEP’s reportable segment income statement information for the three and nine months ended September 30, 20212022 and 20202021 and reportable segment balance sheet information as of September 30, 20212022 and December 31, 2020.2021.
| | | Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) | | (in millions) |
Revenues from: | Revenues from: | | | | | | | | | | | | Revenues from: | | | | | | | | | | | |
External Customers | External Customers | $ | 2,716.8 | | | $ | 1,195.0 | | | $ | 90.3 | | | $ | 617.4 | | | $ | 3.5 | | | $ | — | | | $ | 4,623.0 | | External Customers | $ | 3,174.6 | | | $ | 1,525.5 | | | $ | 81.9 | | | $ | 733.1 | | | $ | 11.0 | | | $ | — | | | $ | 5,526.1 | |
Other Operating Segments | Other Operating Segments | 42.5 | | | 5.3 | | | 301.3 | | | 3.7 | | | 23.2 | | | (376.0) | | | — | | Other Operating Segments | 51.7 | | | 4.7 | | | 349.0 | | | 2.3 | | | 17.3 | | | (425.0) | | | — | |
Total Revenues | Total Revenues | $ | 2,759.3 | | | $ | 1,200.3 | | | $ | 391.6 | | | $ | 621.1 | | | $ | 26.7 | | | $ | (376.0) | | | $ | 4,623.0 | | Total Revenues | $ | 3,226.3 | | | $ | 1,530.2 | | | $ | 430.9 | | | $ | 735.4 | | | $ | 28.3 | | | $ | (425.0) | | | $ | 5,526.1 | |
| | Net Income (Loss) | Net Income (Loss) | $ | 438.7 | | | $ | 155.9 | | | $ | 167.9 | | | $ | 99.5 | | | $ | (65.1) | | | $ | — | | | $ | 796.9 | | Net Income (Loss) | $ | 476.9 | | | $ | 165.5 | | | $ | 171.4 | | | $ | 96.2 | | | $ | (226.7) | | | $ | — | | | $ | 683.3 | |
| | | Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) | | (in millions) |
Revenues from: | Revenues from: | | | | | | | | | | | | Revenues from: | | | | | | | | | | | |
External Customers | External Customers | $ | 2,400.1 | | | $ | 1,124.1 | | | $ | 73.4 | | | $ | 464.8 | | | $ | 4.0 | | | $ | — | | | $ | 4,066.4 | | External Customers | $ | 2,716.8 | | | $ | 1,195.0 | | | $ | 90.3 | | | $ | 617.4 | | | $ | 3.5 | | | $ | — | | | $ | 4,623.0 | |
Other Operating Segments | Other Operating Segments | 34.7 | | | 41.2 | | | 244.5 | | | 25.2 | | | 28.6 | | | (374.2) | | | — | | Other Operating Segments | 42.5 | | | 5.3 | | | 301.3 | | | 3.7 | | | 23.2 | | | (376.0) | | | — | |
Total Revenues | Total Revenues | $ | 2,434.8 | | | $ | 1,165.3 | | | $ | 317.9 | | | $ | 490.0 | | | $ | 32.6 | | | $ | (374.2) | | | $ | 4,066.4 | | Total Revenues | $ | 2,759.3 | | | $ | 1,200.3 | | | $ | 391.6 | | | $ | 621.1 | | | $ | 26.7 | | | $ | (376.0) | | | $ | 4,623.0 | |
| | Net Income (Loss) | Net Income (Loss) | $ | 394.2 | | | $ | 147.4 | | | $ | 139.3 | | | $ | 114.6 | | | $ | (47.3) | | | $ | — | | | $ | 748.2 | | Net Income (Loss) | $ | 438.7 | | | $ | 155.9 | | | $ | 167.9 | | | $ | 99.5 | | | $ | (65.1) | | | $ | — | | | $ | 796.9 | |
| | | | | | | | |
| | | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) | | (in millions) |
Revenues from: | Revenues from: | | Revenues from: | |
External Customers | External Customers | $ | 7,445.9 | | | $ | 3,366.9 | | | $ | 264.6 | | | $ | 1,641.6 | | | $ | 11.6 | | | $ | — | | | $ | 12,730.6 | | External Customers | $ | 8,416.4 | | | $ | 4,064.5 | | | $ | 244.4 | | | $ | 1,997.0 | | | $ | 36.1 | | | $ | — | | | $ | 14,758.4 | |
Other Operating Segments | Other Operating Segments | 111.3 | | | 24.9 | | | 882.2 | | | 50.3 | | | 43.5 | | | (1,112.2) | | | — | | Other Operating Segments | 145.8 | | | 14.1 | | | 976.7 | | | 17.3 | | | 36.6 | | | (1,190.5) | | | — | |
Total Revenues | Total Revenues | $ | 7,557.2 | | | $ | 3,391.8 | | | $ | 1,146.8 | | | $ | 1,691.9 | | | $ | 55.1 | | | $ | (1,112.2) | | | $ | 12,730.6 | | Total Revenues | $ | 8,562.2 | | | $ | 4,078.6 | | | $ | 1,221.1 | | | $ | 2,014.3 | | | $ | 72.7 | | | $ | (1,190.5) | | | $ | 14,758.4 | |
| | Net Income (Loss) | Net Income (Loss) | $ | 938.9 | | | $ | 424.0 | | | $ | 510.7 | | | $ | 184.2 | | | $ | (108.3) | | | $ | — | | | $ | 1,949.5 | | Net Income (Loss) | $ | 1,079.4 | | | $ | 483.1 | | | $ | 487.8 | | | $ | 278.1 | | | $ | (406.2) | | | $ | — | | | $ | 1,922.2 | |
| | | Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) | | (in millions) |
Revenues from: | Revenues from: | | Revenues from: | |
External Customers | External Customers | $ | 6,655.4 | | | $ | 3,208.7 | | | $ | 215.7 | | | $ | 1,223.4 | | | $ | 4.7 | | | $ | — | | | $ | 11,307.9 | | External Customers | $ | 7,445.9 | | | $ | 3,366.9 | | | $ | 264.6 | | | $ | 1,641.6 | | | $ | 11.6 | | | $ | — | | | $ | 12,730.6 | |
Other Operating Segments | Other Operating Segments | 98.1 | | | 98.0 | | | 662.1 | | | 82.1 | | | 67.3 | | | (1,007.6) | | | — | | Other Operating Segments | 111.3 | | | 24.9 | | | 882.2 | | | 50.3 | | | 43.5 | | | (1,112.2) | | | — | |
Total Revenues | Total Revenues | $ | 6,753.5 | | | $ | 3,306.7 | | | $ | 877.8 | | | $ | 1,305.5 | | | $ | 72.0 | | | $ | (1,007.6) | | | $ | 11,307.9 | | Total Revenues | $ | 7,557.2 | | | $ | 3,391.8 | | | $ | 1,146.8 | | | $ | 1,691.9 | | | $ | 55.1 | | | $ | (1,112.2) | | | $ | 12,730.6 | |
| | Net Income (Loss) | Net Income (Loss) | $ | 896.8 | | | $ | 403.1 | | | $ | 373.1 | | | $ | 203.6 | | | $ | (114.6) | | | $ | — | | | $ | 1,762.0 | | Net Income (Loss) | $ | 938.9 | | | $ | 424.0 | | | $ | 510.7 | | | $ | 184.2 | | | $ | (108.3) | | | $ | — | | | $ | 1,949.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
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Total Assets (d) | | $ | 49,056.9 | | | $ | 22,139.7 | | | $ | 14,708.9 | | | $ | 5,376.3 | | | $ | 6,278.3 | | (b) | $ | (6,310.7) | | (c) | $ | 91,249.4 | |
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| | September 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 | | $ | 50,990.6 | | | $ | 22,171.7 | | | $ | 12,865.6 | | | $ | 2,125.8 | | | $ | 414.5 | | | $ | — | | | $ | 88,568.2 | |
Accumulated Depreciation and Amortization | | 16,647.1 | | | 4,059.9 | | | 758.1 | | | 222.8 | | | 189.1 | | | — | | | 21,877.0 | |
Total Property Plant and Equipment - Net | | $ | 34,343.5 | | | $ | 18,111.8 | | | $ | 12,107.5 | | | $ | 1,903.0 | | | $ | 225.4 | | | $ | — | | | $ | 66,691.2 | |
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Total Assets | | $ | 45,775.5 | | | $ | 21,053.1 | | | $ | 13,287.6 | | | $ | 4,387.6 | | | $ | 6,421.4 | | (b) | $ | (4,588.1) | | (c) | $ | 86,337.1 | |
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Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Nonaffiliated | | $ | 1,243.0 | | | $ | 815.2 | | | $ | 52.4 | | | $ | — | | | $ | 411.2 | | (d) | $ | — | | | $ | 2,521.8 | |
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Long-term Debt: | | | | | | | | | | | | | | |
Affiliated | | 65.0 | | | — | | | — | | | — | | | — | | | (65.0) | | | — | |
Nonaffiliated | | 13,616.0 | | | 7,869.0 | | | 4,544.2 | | | — | | | 6,027.3 | | (d) | — | | | 32,056.5 | |
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Total Long-term Debt | | $ | 14,924.0 | | | $ | 8,684.2 | | | $ | 4,596.6 | | | $ | — | | | $ | 6,438.5 | | (d) | $ | (65.0) | | | $ | 34,578.3 | |
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| | 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 | |
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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 | |
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Long-term Debt Due Within One Year: | | | | | | | | | | | | | | |
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Nonaffiliated | | $ | 1,034.6 | | | $ | 588.8 | | | $ | 52.3 | | | $ | — | | | $ | 410.4 | | (d) | $ | — | | | $ | 2,086.1 | |
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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 | |
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Total Long-term Debt | | $ | 13,475.2 | | | $ | 7,250.7 | | | $ | 4,128.0 | | | $ | — | | | $ | 6,283.6 | | (d) | $ | (65.0) | | | $ | 31,072.5 | |
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| | December 31, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other (a) | | Reconciling Adjustments | | Consolidated |
| | (in millions) |
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Total Assets (d) | | $ | 46,974.2 | | | $ | 21,120.2 | | | $ | 13,873.3 | | | $ | 4,263.6 | | | $ | 5,846.5 | | (b) | $ | (4,409.1) | | (c) | $ | 87,668.7 | |
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(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 inclusiveAmount includes Assets Held for Sale on the balance sheet. See “Disposition of the impact of fair value hedge accounting. See “Accounting for Fair Value Hedging Strategies”KPCo and KTCo” section of Note 106 for additional information.
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 nine months ended September 30, 20212022 and 20202021 and reportable segment balance sheet information as of September 30, 20212022 and December 31, 2020.2021.
| | | | Three Months Ended September 30, 2022 |
| | | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | | (in millions) |
Revenues from: | | Revenues from: | |
External Customers | | External Customers | $ | 87.2 | | | $ | — | | | $ | — | | | $ | 87.2 | |
Sales to AEP Affiliates | | Sales to AEP Affiliates | 331.3 | | | — | | | — | | | 331.3 | |
| Total Revenues | | Total Revenues | $ | 418.5 | | | $ | — | | | $ | — | | | $ | 418.5 | |
| | Net Income | | Net Income | $ | 152.6 | | | $ | 0.1 | | (a) | $ | — | | | $ | 152.7 | |
| | | Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2021 |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated | | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| | (in millions) | | (in millions) |
Revenues from: | Revenues from: | | Revenues from: | |
External Customers | External Customers | $ | 79.2 | | | $ | — | | | $ | — | | | $ | 79.2 | | External Customers | $ | 79.2 | | | $ | — | | | $ | — | | | $ | 79.2 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | 297.6 | | | — | | | — | | | 297.6 | | Sales to AEP Affiliates | 297.6 | | | — | | | — | | | 297.6 | |
Other Revenues | Other Revenues | 0.2 | | | — | | | — | | | 0.2 | | Other Revenues | 0.2 | | | — | | | — | | | 0.2 | |
Total Revenues | Total Revenues | $ | 377.0 | | | $ | — | | | $ | — | | | $ | 377.0 | | Total Revenues | $ | 377.0 | | | $ | — | | | $ | — | | | $ | 377.0 | |
| Interest Income | $ | 0.1 | | | $ | 40.3 | | | $ | (40.2) | | (a) | $ | 0.2 | | |
Interest Expense | 36.1 | | | 40.2 | | | (40.2) | | (a) | 36.1 | | |
Income Tax Expense | 36.7 | | | — | | | — | | | 36.7 | | |
| | Net Income | $ | 145.3 | | | $ | 0.1 | | (b) | $ | — | | | $ | 145.4 | | |
| | | Three Months Ended September 30, 2020 | |
| | State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated | |
| | (in millions) | |
Revenues from: | | |
External Customers | $ | 62.9 | | | $ | — | | | $ | — | | | $ | 62.9 | | |
Sales to AEP Affiliates | 241.2 | | | — | | | — | | | 241.2 | | |
| Total Revenues | $ | 304.1 | | | $ | — | | | $ | — | | | $ | 304.1 | | |
| Interest Income | $ | — | | | $ | 38.4 | | | $ | (38.2) | | (a) | $ | 0.2 | | |
Interest Expense | 32.7 | | | 38.2 | | | (38.2) | | (a) | 32.7 | | |
Income Tax Expense | 31.7 | | | — | | | — | | | 31.7 | | |
| | Net Income | Net Income | $ | 117.5 | | | $ | 0.1 | | (b) | $ | — | | | $ | 117.6 | | Net Income | $ | 145.3 | | | $ | 0.1 | | (a) | $ | — | | | $ | 145.4 | |
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| Nine Months Ended September 30, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 239.3 | | | $ | — | | | $ | — | | | $ | 239.3 | |
Sales to AEP Affiliates | 864.6 | | — | | | — | | | 864.6 | |
Other Revenues | 0.3 | | | — | | | — | | | 0.3 | |
Total Revenues | $ | 1,104.2 | | | $ | — | | | $ | — | | | $ | 1,104.2 | |
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Interest Income | $ | 0.1 | | | $ | 117.0 | | | $ | (116.7) | | (a) | $ | 0.4 | |
Interest Expense | 104.5 | | | 116.6 | | | (116.6) | | (a) | 104.5 | |
Income Tax Expense | 115.4 | | | — | | | — | | | 115.4 | |
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Net Income | $ | 445.5 | | | $ | 0.2 | | (b) | $ | — | | | $ | 445.7 | |
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| Nine Months Ended September 30, 2020 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 184.6 | | | $ | — | | | $ | — | | | $ | 184.6 | |
Sales to AEP Affiliates | 652.6 | | — | | | — | | | 652.6 | |
Other Revenues | 0.6 | | | — | | | — | | | 0.6 | |
Total Revenues | $ | 837.8 | | | $ | — | | | $ | — | | | $ | 837.8 | |
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Interest Income | $ | 0.9 | | | $ | 111.3 | | | $ | (109.9) | | (a) | $ | 2.3 | |
Interest Expense | 95.1 | | 109.9 | | (109.9) | | (a) | 95.1 |
Income Tax Expense | 82.7 | | | 0.1 | | | — | | | 82.8 | |
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Net Income | $ | 308.0 | | | $ | 1.1 | | (b) | $ | — | | | $ | 309.1 | |
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| September 30, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Total Transmission Property | $ | 12,359.3 | | | $ | — | | | $ | — | | | $ | 12,359.3 | |
Accumulated Depreciation and Amortization | 730.4 | | | — | | | — | | | 730.4 | |
Total Transmission Property – Net | $ | 11,628.9 | | | $ | — | | | $ | — | | | $ | 11,628.9 | |
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Notes Receivable - Affiliated | $ | — | | | $ | 4,343.5 | | | $ | (4,343.5) | | (c) | $ | — | |
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Total Assets | $ | 11,984.7 | | | $ | 4,445.3 | | (d) | $ | (4,498.9) | | (e) | $ | 11,931.1 | |
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Total Long-term Debt | $ | 4,440.0 | | | $ | 4,393.4 | | | $ | (4,440.0) | | (c) | $ | 4,393.4 | |
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| 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 | |
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Notes Receivable - Affiliated | $ | — | | | $ | 3,948.5 | | | $ | (3,948.5) | | (c) | $ | — | |
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Total Assets | $ | 11,185.1 | | | $ | 4,084.0 | | (d) | $ | (4,023.1) | | (e) | $ | 11,246.0 | |
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Total Long-term Debt | $ | 3,990.0 | | | $ | 3,948.5 | | | $ | (3,990.0) | | (c) | $ | 3,948.5 | |
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| Nine Months Ended September 30, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 249.5 | | | $ | — | | | $ | — | | | $ | 249.5 | |
Sales to AEP Affiliates | 933.8 | | | — | | | — | | | 933.8 | |
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Total Revenues | $ | 1,183.3 | | | $ | — | | | $ | — | | | $ | 1,183.3 | |
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Net Income | $ | 426.4 | | | $ | 0.2 | | (a) | $ | — | | | $ | 426.6 | |
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| Nine Months Ended September 30, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
Revenues from: | | | | | | | |
External Customers | $ | 239.3 | | | $ | — | | | $ | — | | | $ | 239.3 | |
Sales to AEP Affiliates | 864.6 | | | — | | | — | | | 864.6 | |
Other Revenues | 0.3 | | | — | | | — | | | 0.3 | |
Total Revenues | $ | 1,104.2 | | | $ | — | | | $ | — | | | $ | 1,104.2 | |
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Net Income | $ | 445.5 | | | $ | 0.2 | | (a) | $ | — | | | $ | 445.7 | |
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| September 30, 2022 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
| (in millions) |
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Total Assets (d) | $ | 13,359.9 | | | $ | 4,972.4 | | (b) | $ | (5,013.1) | | (c) | $ | 13,319.2 | |
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| December 31, 2021 |
| State Transcos | | AEPTCo Parent | | Reconciling Adjustments | | AEPTCo Consolidated |
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Total Assets (d) | $ | 12,564.3 | | | $ | 4,389.5 | | (b) | $ | (4,429.4) | | (c) | $ | 12,524.4 | |
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(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)(b)Includes the elimination of AEPTCo Parent’s investments in State Transcos.
(e)(c)Primarily relates to the elimination of Notes Receivable from the State Transcos.
(d)Amount includes Assets Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
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 certain 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.
The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts:
Notional Volume of Derivative Instruments
September 30, 20212022
| Primary Risk Exposure | Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in millions) | | | | | (in millions) |
Commodity: | Commodity: | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | |
Power | Power | | MWhs | | 341.9 | | | — | | | 55.4 | | | 23.1 | | | 2.8 | | | 18.7 | | | 5.4 | | Power | | MWhs | | 260.6 | | | — | | | 29.0 | | | 6.2 | | | 2.6 | | | 5.7 | | | 4.3 | |
| Natural Gas | Natural Gas | | MMBtus | | 28.1 | | | — | | | — | | | — | | | — | | | — | | | 5.2 | | Natural Gas | | MMBtus | | 80.3 | | | — | | | — | | | — | | | — | | | — | | | 1.8 | |
Heating Oil and Gasoline | Heating Oil and Gasoline | | Gallons | | 7.8 | | | 2.0 | | | 1.2 | | | 0.7 | | | 1.5 | | | 0.9 | | | 1.1 | | Heating Oil and Gasoline | | Gallons | | 6.4 | | | 1.7 | | | 0.9 | | | 0.6 | | | 1.3 | | | 0.7 | | | 0.9 | |
Interest Rate | Interest Rate | | USD | | $ | 116.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Interest Rate | | USD | | $ | 99.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Interest Rate on Long-term Debt | Interest Rate on Long-term Debt | | USD | | $ | 1,250.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Interest Rate on Long-term Debt | | USD | | $ | 1,150.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
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December 31, 20202021
| Primary Risk Exposure | Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | Primary Risk Exposure | | Unit of Measure | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in millions) | | | | | (in millions) |
Commodity: | Commodity: | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | |
Power | Power | | MWhs | | 331.3 | | | — | | | 46.9 | | | 19.7 | | | 3.0 | | | 11.9 | | | 4.0 | | Power | | MWhs | | 287.9 | | | — | | | 33.1 | | | 13.6 | | | 2.7 | | | 11.9 | | | 3.4 | |
| Natural Gas | Natural Gas | | MMBtus | | 26.9 | | | — | | | — | | | — | | | — | | | — | | | 7.9 | | Natural Gas | | MMBtus | | 34.1 | | | — | | | — | | | — | | | — | | | 1.3 | | | 5.1 | |
Heating Oil and Gasoline | Heating Oil and Gasoline | | Gallons | | 6.9 | | | 1.8 | | | 1.1 | | | 0.6 | | | 1.4 | | | 0.7 | | | 0.9 | | Heating Oil and Gasoline | | Gallons | | 7.4 | | | 1.9 | | | 1.1 | | | 0.7 | | | 1.5 | | | 0.8 | | | 1.0 | |
Interest Rate | Interest Rate | | USD | | $ | 129.8 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Interest Rate | | USD | | $ | 116.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Interest Rate on Long-term Debt | Interest Rate on Long-term Debt | | USD | | $ | 1,150.0 | | | $ | — | | | $ | 200.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Interest Rate on Long-term Debt | | USD | | $ | 950.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
|
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.
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 RegistrantsAEP netted cash collateral received from third partiesthird-parties against short-term and long-term risk management assets in the amounts of $847 million and $263 million as of September 30, 2022 and December 31, 2021, respectively. AEP netted cash collateral paid to third-parties against short-term and long-term risk management liabilities in the amounts of $0 and $3 million as of September 30, 2022 and December 31, 2021, respectively. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third partiesthird-parties against short-term and long-term risk management liabilities as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 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 | | $ | 309.7 | | | $ | 38.3 | | | $ | 3.4 | | | $ | 6.8 | |
APCo | | 0.6 | | | 10.7 | | | 0.4 | | | — | |
I&M | | 0.3 | | | 17.4 | | | 1.7 | | | — | |
Amountswere immaterial for AEP Texas, OPCo, PSO and SWEPCo are immaterialthe Registrant Subsidiaries as of September 30, 20212022 and December 31, 2020, respectively.2021.
The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets:sheets. Unless shown as a separate line on the balance sheets due to materiality, Current Risk Management Assets are included in Prepayments and Other Current Assets, Long-term Risk Management Assets are included in Deferred Charges and Other Noncurrent Assets, Current Risk Management Liabilities are included in Other Current Liabilities and Long-term Risk Management Liabilities are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets.
AEP
| | | September 30, 2021 | | September 30, 2022 |
| | 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) | | 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 | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets(d) | Current Risk Management Assets(d) | | $ | 1,005.5 | | | $ | 321.1 | | | $ | 8.3 | | | $ | 1,334.9 | | | $ | (965.7) | | | $ | 369.2 | | Current Risk Management Assets(d) | | $ | 1,482.1 | | | $ | 411.1 | | | $ | 8.8 | | | $ | 1,902.0 | | | $ | (1,331.8) | | | $ | 570.2 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 337.3 | | | 85.8 | | | — | | | 423.1 | | | (144.8) | | | 278.3 | | Long-term Risk Management Assets | | 686.6 | | | 177.4 | | | — | | | 864.0 | | | (598.2) | | | 265.8 | |
Total Assets | Total Assets | | 1,342.8 | | | 406.9 | | | 8.3 | | | 1,758.0 | | | (1,110.5) | | | 647.5 | | Total Assets | | 2,168.7 | | | 588.5 | | | 8.8 | | | 2,766.0 | | | (1,930.0) | | | 836.0 | |
| Current Risk Management Liabilities(e) | Current Risk Management Liabilities(e) | | 834.5 | | | 33.1 | | | — | | | 867.6 | | | (761.1) | | | 106.5 | | Current Risk Management Liabilities(e) | | 1,005.7 | | | 10.9 | | | 21.3 | | | 1,037.9 | | | (850.6) | | | 187.3 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 234.6 | | | 14.3 | | | 28.8 | | | 277.7 | | | (78.1) | | | 199.6 | | Long-term Risk Management Liabilities | | 501.6 | | | 4.9 | | | 114.1 | | | 620.6 | | | (232.4) | | | 388.2 | |
Total Liabilities | Total Liabilities | | 1,069.1 | | | 47.4 | | | 28.8 | | | 1,145.3 | | | (839.2) | | | 306.1 | | Total Liabilities | | 1,507.3 | | | 15.8 | | | 135.4 | | | 1,658.5 | | | (1,083.0) | | | 575.5 | |
| Total MTM Derivative Contract Net Assets (Liabilities)(f) | Total MTM Derivative Contract Net Assets (Liabilities)(f) | | $ | 273.7 | | | $ | 359.5 | | | $ | (20.5) | | | $ | 612.7 | | | $ | (271.3) | | | $ | 341.4 | | Total MTM Derivative Contract Net Assets (Liabilities)(f) | | $ | 661.4 | | | $ | 572.7 | | | $ | (126.6) | | | $ | 1,107.5 | | | $ | (847.0) | | | $ | 260.5 | |
| | | December 31, 2020 | | December 31, 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) | | 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 | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Interest Rate (a) | |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets(d) | Current Risk Management Assets(d) | | $ | 239.1 | | | $ | 21.1 | | | $ | 5.0 | | | $ | 265.2 | | | $ | (170.5) | | | $ | 94.7 | | Current Risk Management Assets(d) | | $ | 513.4 | | | $ | 176.0 | | | $ | 1.2 | | | $ | 690.6 | | | $ | (496.2) | | | $ | 194.4 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 275.9 | | | 18.0 | | | — | | | 293.9 | | | (51.7) | | | 242.2 | | Long-term Risk Management Assets | | 370.5 | | | 89.1 | | | — | | | 459.6 | | | (192.6) | | | 267.0 | |
Total Assets | Total Assets | | 515.0 | | | 39.1 | | | 5.0 | | | 559.1 | | | (222.2) | | | 336.9 | | Total Assets | | 883.9 | | | 265.1 | | | 1.2 | | | 1,150.2 | | | (688.8) | | | 461.4 | |
| Current Risk Management Liabilities(e) | Current Risk Management Liabilities(e) | | 193.0 | | | 54.4 | | | 3.4 | | | 250.8 | | | (172.0) | | | 78.8 | | Current Risk Management Liabilities(e) | | 395.7 | | | 40.9 | | | — | | | 436.6 | | | (361.2) | | | 75.4 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 222.2 | | | 60.1 | | | 4.1 | | | 286.4 | | | (53.6) | | | 232.8 | | Long-term Risk Management Liabilities | | 243.9 | | | 16.7 | | | 38.1 | | | 298.7 | | | (68.4) | | | 230.3 | |
Total Liabilities | Total Liabilities | | 415.2 | | | 114.5 | | | 7.5 | | | 537.2 | | | (225.6) | | | 311.6 | | Total Liabilities | | 639.6 | | | 57.6 | | | 38.1 | | | 735.3 | | | (429.6) | | | 305.7 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 99.8 | | | $ | (75.4) | | | $ | (2.5) | | | $ | 21.9 | | | $ | 3.4 | | | $ | 25.3 | | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 244.3 | | | $ | 207.5 | | | $ | (36.9) | | | $ | 414.9 | | | $ | (259.2) | | | $ | 155.7 | |
AEP Texas
| | | September 30, 2021 | | September 30, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 0.8 | | | $ | (0.8) | | | $ | — | | Current Risk Management Assets | | $ | 0.1 | | | $ | 0.1 | | | $ | 0.2 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 0.1 | | | (0.1) | | | — | | Long-term Risk Management Assets | | (0.1) | | | 0.2 | | | 0.1 | |
Total Assets | Total Assets | | 0.9 | | | (0.9) | | | — | | Total Assets | | — | | | 0.3 | | | 0.3 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | — | | | — | | | — | | Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | — | | | — | | | — | | Long-term Risk Management Liabilities | | — | | | 0.1 | | | 0.1 | |
Total Liabilities | Total Liabilities | | — | | | — | | | — | | Total Liabilities | | — | | | 0.1 | | | 0.1 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.9 | | | $ | (0.9) | | | $ | — | | |
Total MTM Derivative Contract Net Assets | | Total MTM Derivative Contract Net Assets | | $ | — | | | $ | 0.2 | | | $ | 0.2 | |
| | | December 31, 2020 | | December 31, 2021 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 0.4 | | | $ | (0.4) | | | $ | — | | Current Risk Management Assets | | $ | 0.6 | | | $ | (0.6) | | | $ | — | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | — | | | — | | | — | | Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | Total Assets | | 0.4 | | | (0.4) | | | — | | Total Assets | | 0.6 | | | (0.6) | | | — | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | — | | | — | | | — | | Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | — | | | — | | | — | | Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | Total Liabilities | | — | | | — | | | — | | Total Liabilities | | — | | | — | | | — | |
| Total MTM Derivative Contract Net Assets (Liabilities) | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.4 | | | $ | (0.4) | | | $ | — | | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 0.6 | | | $ | (0.6) | | | $ | — | |
APCo
| | | September 30, 2021 | | September 30, 2022 |
| | | Risk Management | | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | | | in the Statement of | | Presented in the Statement | | Contracts – | | | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | | | Financial Position (b) | | of Financial Position (c) | Balance Sheet Location | | Commodity (a) | | | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 95.7 | | | | | $ | (48.7) | | | $ | 47.0 | | Current Risk Management Assets | | $ | 106.8 | | | | | $ | — | | | $ | 106.8 | |
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets | | 0.2 | | | | | (0.2) | | | — | | |
Long-term Risk Management Assets | | Long-term Risk Management Assets | | 0.7 | | | | | (0.6) | | | 0.1 | |
Total Assets | Total Assets | | 95.9 | | | | | (48.9) | | | 47.0 | | Total Assets | | 107.5 | | | | | (0.6) | | | 106.9 | |
| Other Current Liabilities - Current Risk Management Liabilities | | 60.2 | | | | | (58.9) | | | 1.3 | | |
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities | | 0.2 | | | | | (0.2) | | | — | | |
Current Risk Management Liabilities | | Current Risk Management Liabilities | | — | | | | | — | | | — | |
Long-term Risk Management Liabilities | | Long-term Risk Management Liabilities | | 0.7 | | | | | (0.7) | | | — | |
Total Liabilities | Total Liabilities | | 60.4 | | | | | (59.1) | | | 1.3 | | Total Liabilities | | 0.7 | | | | | (0.7) | | | — | |
| Total MTM Derivative Contract Net Assets(f) | Total MTM Derivative Contract Net Assets(f) | | $ | 35.5 | | | | | $ | 10.2 | | | $ | 45.7 | | Total MTM Derivative Contract Net Assets(f) | | $ | 106.8 | | | | | $ | 0.1 | | | $ | 106.9 | |
| | | December 31, 2020 | | December 31, 2021 |
| | | Gross Amounts | | |
| | Risk | | of Risk | | Gross Amounts | | Net Amounts of Assets/ | |
| | Management | | Hedging | | Management | | Offset in the | | Liabilities Presented in | | Risk Management | | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | Contracts – | | Assets/Liabilities | | Statement of | | the Statement of | | Contracts – | | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Interest Rate (a) | | Recognized | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 38.8 | | | $ | 2.4 | | | $ | 41.2 | | | $ | (18.8) | | | $ | 22.4 | | Current Risk Management Assets | | $ | 47.5 | | | | $ | (5.5) | | | $ | 42.0 | |
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets | | 0.7 | | | — | | | 0.7 | | | (0.6) | | | 0.1 | | |
Long-term Risk Management Assets | | Long-term Risk Management Assets | | 0.2 | | | | (0.2) | | | — | |
Total Assets | Total Assets | | 39.5 | | | 2.4 | | | 41.9 | | | (19.4) | | | 22.5 | | Total Assets | | 47.7 | | | | (5.7) | | | 42.0 | |
| 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 | | |
Current Risk Management Liabilities | | Current Risk Management Liabilities | | 7.2 | | | | (6.4) | | | 0.8 | |
Long-term Risk Management Liabilities | | Long-term Risk Management Liabilities | | 0.2 | | | | (0.2) | | | — | |
Total Liabilities | Total Liabilities | | 20.3 | | | 3.4 | | | 23.7 | | | (19.0) | | | 4.7 | | Total Liabilities | | 7.4 | | | | (6.6) | | | 0.8 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 19.2 | | | $ | (1.0) | | | $ | 18.2 | | | $ | (0.4) | | | $ | 17.8 | | |
Total MTM Derivative Contract Net Assets | | Total MTM Derivative Contract Net Assets | | $ | 40.3 | | | | $ | 0.9 | | | $ | 41.2 | |
I&M
| | | September 30, 2021 | | September 30, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 37.8 | | | $ | (32.3) | | | $ | 5.5 | | Current Risk Management Assets | | $ | 12.3 | | | $ | (0.9) | | | $ | 11.4 | |
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets | | 0.1 | | | (0.1) | | | — | | |
Long-term Risk Management Assets | | Long-term Risk Management Assets | | 0.6 | | | (0.4) | | | 0.2 | |
Total Assets | Total Assets | | 37.9 | | | (32.4) | | | 5.5 | | Total Assets | | 12.9 | | | (1.3) | | | 11.6 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 51.9 | | | (49.4) | | | 2.5 | | Current Risk Management Liabilities | | 0.9 | | | (0.9) | | | — | |
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities | | 0.1 | | | (0.1) | | | — | | |
Long-term Risk Management Liabilities | | Long-term Risk Management Liabilities | | 0.5 | | | (0.5) | | | — | |
Total Liabilities | Total Liabilities | | 52.0 | | | (49.5) | | | 2.5 | | Total Liabilities | | 1.4 | | | (1.4) | | | — | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (14.1) | | | $ | 17.1 | | | $ | 3.0 | | |
Total MTM Derivative Contract Net Assets (f) | | Total MTM Derivative Contract Net Assets (f) | | $ | 11.5 | | | $ | 0.1 | | | $ | 11.6 | |
| | | December 31, 2020 | | December 31, 2021 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 17.2 | | | $ | (13.6) | | | $ | 3.6 | | Current Risk Management Assets | | $ | 11.1 | | | $ | (7.8) | | | $ | 3.3 | |
Deferred Charges and Other Noncurrent Assets - Long-term Risk Management Assets | | 0.5 | | | (0.4) | | | 0.1 | | |
Long-term Risk Management Assets | | Long-term Risk Management Assets | | 0.2 | | | (0.2) | | | — | |
Total Assets | Total Assets | | 17.7 | | | (14.0) | | | 3.7 | | Total Assets | | 11.3 | | | (8.0) | | | 3.3 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 12.1 | | | (12.0) | | | 0.1 | | Current Risk Management Liabilities | | 14.8 | | | (9.8) | | | 5.0 | |
Deferred Credits and Other Noncurrent Liabilities - Long-term Risk Management Liabilities | | 0.4 | | | (0.3) | | | 0.1 | | |
Long-term Risk Management Liabilities | | Long-term Risk Management Liabilities | | 0.2 | | | (0.2) | | | — | |
Total Liabilities | Total Liabilities | | 12.5 | | | (12.3) | | | 0.2 | | Total Liabilities | | 15.0 | | | (10.0) | | | 5.0 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 5.2 | | | $ | (1.7) | | | $ | 3.5 | | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | (3.7) | | | $ | 2.0 | | | $ | (1.7) | |
OPCo
| | | September 30, 2021 | | September 30, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 0.6 | | | $ | (0.6) | | | $ | — | | Current Risk Management Assets | | $ | 2.0 | | | $ | 0.1 | | | $ | 2.1 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 0.1 | | | (0.1) | | | — | | Long-term Risk Management Assets | | (0.1) | | | 0.1 | | | — | |
Total Assets | Total Assets | | 0.7 | | | (0.7) | | | — | | Total Assets | | 1.9 | | | 0.2 | | | 2.1 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 3.5 | | | — | | | 3.5 | | Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 86.9 | | | — | | | 86.9 | | Long-term Risk Management Liabilities | | 45.1 | | | — | | | 45.1 | |
Total Liabilities | Total Liabilities | | 90.4 | | | — | | | 90.4 | | Total Liabilities | | 45.1 | | | — | | | 45.1 | |
| Total MTM Derivative Contract Net Liabilities | | $ | (89.7) | | | $ | (0.7) | | | $ | (90.4) | | |
Total MTM Derivative Contract Net Assets (Liabilities) (f) | | Total MTM Derivative Contract Net Assets (Liabilities) (f) | | $ | (43.2) | | | $ | 0.2 | | | $ | (43.0) | |
| | | December 31, 2020 | | December 31, 2021 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 0.3 | | | $ | (0.3) | | | $ | — | | Current Risk Management Assets | | $ | 0.5 | | | $ | (0.5) | | | $ | — | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | — | | | — | | | — | | Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | Total Assets | | 0.3 | | | (0.3) | | | — | | Total Assets | | 0.5 | | | (0.5) | | | — | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 8.7 | | | — | | | 8.7 | | Current Risk Management Liabilities | | 6.7 | | | — | | | 6.7 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 101.6 | | | — | | | 101.6 | | Long-term Risk Management Liabilities | | 85.8 | | | — | | | 85.8 | |
Total Liabilities | Total Liabilities | | 110.3 | | | — | | | 110.3 | | Total Liabilities | | 92.5 | | | — | | | 92.5 | |
| Total MTM Derivative Contract Net Liabilities | Total MTM Derivative Contract Net Liabilities | | $ | (110.0) | | | $ | (0.3) | | | $ | (110.3) | | Total MTM Derivative Contract Net Liabilities | | $ | (92.0) | | | $ | (0.5) | | | $ | (92.5) | |
PSO
| | | September 30, 2021 | | September 30, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 19.0 | | | $ | (0.5) | | | $ | 18.5 | | Current Risk Management Assets | | $ | 44.4 | | | $ | 0.1 | | | $ | 44.5 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | — | | | — | | | — | | Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | Total Assets | | 19.0 | | | (0.5) | | | 18.5 | | Total Assets | | 44.4 | | | 0.1 | | | 44.5 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 0.2 | | | (0.2) | | | — | | Current Risk Management Liabilities | | — | | | — | | | — | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | — | | | — | | | — | | Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | Total Liabilities | | 0.2 | | | (0.2) | | | — | | Total Liabilities | | — | | | — | | | — | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 18.8 | | | $ | (0.3) | | | $ | 18.5 | | |
Total MTM Derivative Contract Net Assets (f) | | Total MTM Derivative Contract Net Assets (f) | | $ | 44.4 | | | $ | 0.1 | | | $ | 44.5 | |
| | | December 31, 2020 | | December 31, 2021 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 10.5 | | | $ | (0.2) | | | $ | 10.3 | | Current Risk Management Assets | | $ | 12.4 | | | $ | (0.3) | | | $ | 12.1 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | — | | | — | | | — | | Long-term Risk Management Assets | | — | | | — | | | — | |
Total Assets | Total Assets | | 10.5 | | | (0.2) | | | 10.3 | | Total Assets | | 12.4 | | | (0.3) | | | 12.1 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | — | | | — | | | — | | Current Risk Management Liabilities | | 3.7 | | | — | | | 3.7 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | — | | | — | | | — | | Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | Total Liabilities | | — | | | — | | | — | | Total Liabilities | | 3.7 | | | — | | | 3.7 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 10.5 | | | $ | (0.2) | | | $ | 10.3 | | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 8.7 | | | $ | (0.3) | | | $ | 8.4 | |
SWEPCo
| | | September 30, 2021 | | September 30, 2022 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 18.1 | | | $ | (0.6) | | | $ | 17.5 | | Current Risk Management Assets | | $ | 37.2 | | | $ | (0.8) | | | $ | 36.4 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | 2.1 | | | — | | | 2.1 | | Long-term Risk Management Assets | | — | | | 0.1 | | | 0.1 | |
Total Assets | Total Assets | | 20.2 | | | (0.6) | | | 19.6 | | Total Assets | | 37.2 | | | (0.7) | | | 36.5 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 0.2 | | | (0.2) | | | — | | Current Risk Management Liabilities | | 0.8 | | | (0.8) | | | — | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | — | | | — | | | — | | Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | Total Liabilities | | 0.2 | | | (0.2) | | | — | | Total Liabilities | | 0.8 | | | (0.8) | | | — | |
| Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 20.0 | | | $ | (0.4) | | | $ | 19.6 | | |
Total MTM Derivative Contract Net Assets (f) | | Total MTM Derivative Contract Net Assets (f) | | $ | 36.4 | | | $ | 0.1 | | | $ | 36.5 | |
| | | December 31, 2020 | | December 31, 2021 |
| | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities | | Risk Management | | Gross Amounts Offset | | Net Amounts of Assets/Liabilities |
| | Contracts – | | in the Statement of | | Presented in the Statement of | | Contracts – | | in the Statement of | | Presented in the Statement of |
Balance Sheet Location | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) | Balance Sheet Location | | Commodity (a) | | Financial Position (b) | | Financial Position (c) |
| | | (in millions) | | | (in millions) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 3.4 | | | $ | (0.2) | | | $ | 3.2 | | Current Risk Management Assets | | $ | 10.1 | | | $ | (0.3) | | | $ | 9.8 | |
Long-term Risk Management Assets | Long-term Risk Management Assets | | — | | | — | | | — | | Long-term Risk Management Assets | | 1.1 | | | — | | | 1.1 | |
Total Assets | Total Assets | | 3.4 | | | (0.2) | | | 3.2 | | Total Assets | | 11.2 | | | (0.3) | | | 10.9 | |
| Current Risk Management Liabilities | Current Risk Management Liabilities | | 0.7 | | | — | | | 0.7 | | Current Risk Management Liabilities | | 2.1 | | | — | | | 2.1 | |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | 1.0 | | | — | | | 1.0 | | Long-term Risk Management Liabilities | | — | | | — | | | — | |
Total Liabilities | Total Liabilities | | 1.7 | | | — | | | 1.7 | | Total Liabilities | | 2.1 | | | — | | | 2.1 | |
| Total MTM Derivative Contract Net Assets (Liabilities) | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 1.7 | | | $ | (0.2) | | | $ | 1.5 | | Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 9.1 | | | $ | (0.3) | | | $ | 8.8 | |
(a)Derivative instruments within these categories are disclosed as 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.
(d)Amount excludes Risk Management Assets of $14.4 million and $6 million as of September 30, 2022 and December 31, 2021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(e)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(f)Increase in amounts as of September 30, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
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 September 30, 2021 | | Three Months Ended September 30, 2022 |
Location of Gain (Loss) | Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) | | | (in millions) |
Vertically Integrated Utilities Revenues | Vertically Integrated Utilities Revenues | | $ | (0.9) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Vertically Integrated Utilities Revenues | | $ | 2.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Generation & Marketing Revenues | Generation & Marketing Revenues | | 128.8 | | | — | | | — | | | — | | | — | | | — | | | — | | Generation & Marketing Revenues | | 116.7 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | (0.9) | | | — | | | — | | | — | | | — | | Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.3 | | | — | | | — | | | — | | | — | |
| Other Revenues - Nonaffiliated | | Other Revenues - Nonaffiliated | | — | | | — | | | — | | | 1.9 | | | — | | | — | | | — | |
Purchased Electricity for Resale | Purchased Electricity for Resale | | 0.2 | | | — | | | 0.1 | | | — | | | — | | | — | | | — | | Purchased Electricity for Resale | | 0.9 | | | — | | | 0.9 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | Other Operation | | 0.9 | | | 0.3 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.2 | | Other Operation | | 1.4 | | | 0.4 | | | 0.1 | | | 0.1 | | | 0.2 | | | 0.2 | | | 0.2 | |
Maintenance | Maintenance | | 1.1 | | | 0.2 | | | 0.2 | | | 0.1 | | | 0.2 | | | 0.1 | | | 0.1 | | Maintenance | | 2.0 | | | 0.5 | | | 0.2 | | | 0.2 | | | 0.4 | | | 0.2 | | | 0.3 | |
Regulatory Assets (a) | Regulatory Assets (a) | | (7.2) | | | — | | | (2.9) | | | (16.9) | | | 14.9 | | | — | | | 0.1 | | Regulatory Assets (a) | | 4.3 | | | — | | | — | | | 0.1 | | | 4.1 | | | — | | | 0.1 | |
Regulatory Liabilities (a) | Regulatory Liabilities (a) | | 46.5 | | | (0.1) | | | 14.2 | | | 1.7 | | | 0.8 | | | 14.0 | | | 12.7 | | Regulatory Liabilities (a) | | 103.2 | | | (1.5) | | | 59.7 | | | 3.8 | | | 0.9 | | | 19.7 | | | 7.0 | |
Total Gain (Loss) on Risk Management Contracts(b) | Total Gain (Loss) on Risk Management Contracts(b) | | $ | 169.4 | | | $ | 0.4 | | | $ | 10.8 | | | $ | (15.0) | | | $ | 16.0 | | | $ | 14.2 | | | $ | 13.1 | | Total Gain (Loss) on Risk Management Contracts(b) | | $ | 230.6 | | | $ | (0.6) | | | $ | 61.2 | | | $ | 6.2 | | | $ | 5.6 | | | $ | 20.1 | | | $ | 7.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2020 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.5 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 11.5 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.3 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 0.3 | | | — | | | 0.2 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | | (0.4) | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.1) | | | (0.1) | |
Maintenance | | (0.8) | | | (0.2) | | | (0.1) | | | (0.1) | | | (0.2) | | | — | | | (0.1) | |
Regulatory Assets (a) | | 7.9 | | | 0.2 | | | 0.4 | | | 0.2 | | | 4.4 | | | (0.4) | | | 2.9 | |
Regulatory Liabilities (a) | | 17.0 | | | — | | | 3.8 | | | 2.6 | | | 1.7 | | | 3.1 | | | 2.0 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 36.0 | | | $ | (0.1) | | | $ | 4.5 | | | $ | 2.7 | | | $ | 5.8 | | | $ | 2.6 | | | $ | 4.7 | |
| | | | Nine Months Ended September 30, 2021 | | Three Months Ended September 30, 2021 |
Location of Gain (Loss) | Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) | | | (in millions) |
Vertically Integrated Utilities Revenues | Vertically Integrated Utilities Revenues | | $ | (0.6) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | Vertically Integrated Utilities Revenues | | $ | (0.9) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Generation & Marketing Revenues | Generation & Marketing Revenues | | 144.9 | | | — | | | — | | | — | | | — | | | — | | | — | | Generation & Marketing Revenues | | 128.8 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | (0.6) | | | — | | | — | | | — | | | — | | Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | (0.9) | | | — | | | — | | | — | | | — | |
| Purchased Electricity for Resale | Purchased Electricity for Resale | | 1.2 | | | — | | | 1.0 | | | 0.1 | | | — | | | — | | | — | | Purchased Electricity for Resale | | 0.2 | | | — | | | 0.1 | | | — | | | — | | | — | | | — | |
Other Operation | Other Operation | | 1.9 | | | 0.6 | | | 0.2 | | | 0.2 | | | 0.3 | | | 0.2 | | | 0.3 | | Other Operation | | 0.9 | | | 0.3 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.1 | | | 0.2 | |
Maintenance | Maintenance | | 2.4 | | | 0.6 | | | 0.4 | | | 0.2 | | | 0.4 | | | 0.2 | | | 0.3 | | Maintenance | | 1.1 | | | 0.2 | | | 0.2 | | | 0.1 | | | 0.2 | | | 0.1 | | | 0.1 | |
Regulatory Assets (a) | Regulatory Assets (a) | | (7.8) | | | — | | | (2.9) | | | (22.9) | | | 20.3 | | | — | | | 1.4 | | Regulatory Assets (a) | | (7.2) | | | — | | | (2.9) | | | (16.9) | | | 14.9 | | | — | | | 0.1 | |
Regulatory Liabilities (a) | Regulatory Liabilities (a) | | 123.6 | | | 0.5 | | | 28.9 | | | 1.9 | | | 5.9 | | | 40.2 | | | 38.5 | | Regulatory Liabilities (a) | | 46.5 | | | (0.1) | | | 14.2 | | | 1.7 | | | 0.8 | | | 14.0 | | | 12.7 | |
Total Gain (Loss) on Risk Management Contracts | Total Gain (Loss) on Risk Management Contracts | | $ | 265.6 | | | $ | 1.7 | | | $ | 27.0 | | | $ | (20.5) | | | $ | 26.9 | | | $ | 40.6 | | | $ | 40.5 | | Total Gain (Loss) on Risk Management Contracts | | $ | 169.4 | | | $ | 0.4 | | | $ | 10.8 | | | $ | (15.0) | | | $ | 16.0 | | | $ | 14.2 | | | $ | 13.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2020 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 0.8 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 11.1 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.4 | | | 0.1 | | | — | | | — | | | 0.1 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 1.2 | | | — | | | 1.0 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | | (1.4) | | | (0.4) | | | (0.2) | | | (0.2) | | | (0.3) | | | (0.2) | | | (0.2) | |
Maintenance | | (2.2) | | | (0.6) | | | (0.3) | | | (0.2) | | | (0.4) | | | (0.2) | | | (0.3) | |
Regulatory Assets (a) | | (8.5) | | | (0.3) | | | (0.1) | | | (0.2) | | | (9.9) | | | (0.6) | | | 2.2 | |
Regulatory Liabilities (a) | | 80.9 | | | — | | | 16.2 | | | 8.8 | | | 8.4 | | | 23.9 | | | 14.8 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 81.9 | | | $ | (1.3) | | | $ | 17.0 | | | $ | 8.4 | | | $ | (2.2) | | | $ | 22.9 | | | $ | 16.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2022 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | 2.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 390.0 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | 0.4 | | | (0.1) | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
Other Revenues - Nonaffiliated | | — | | | — | | | — | | | 1.9 | | | — | | | — | | | — | |
Purchased Electricity for Resale | | 3.3 | | | — | | | 3.0 | | | 0.1 | | | — | | | 0.1 | | | — | |
Other Operation | | 3.7 | | | 1.1 | | | 0.3 | | | 0.4 | | | 0.6 | | | 0.5 | | | 0.6 | |
Maintenance | | 5.2 | | | 1.4 | | | 0.7 | | | 0.5 | | | 0.9 | | | 0.6 | | | 0.8 | |
Regulatory Assets (a) | | 49.3 | | | 0.1 | | | — | | | (1.2) | | | 49.0 | | | 3.6 | | | (2.1) | |
Regulatory Liabilities (a) | | 250.1 | | | (0.6) | | | 79.9 | | | 7.0 | | | 2.5 | | | 71.4 | | | 64.8 | |
Total Gain on Risk Management Contracts (b) | | $ | 703.8 | | | $ | 2.0 | | | $ | 84.3 | | | $ | 8.6 | | | $ | 53.0 | | | $ | 76.2 | | | $ | 64.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2021 |
Location of Gain (Loss) | | AEP | | AEP Texas | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Vertically Integrated Utilities Revenues | | $ | (0.6) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | |
Generation & Marketing Revenues | | 144.9 | | | — | | | — | | | — | | | — | | | — | | | — | |
Electric Generation, Transmission and Distribution Revenues | | — | | | — | | | (0.6) | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Purchased Electricity for Resale | | 1.2 | | | — | | | 1.0 | | | 0.1 | | | — | | | — | | | — | |
Other Operation | | 1.9 | | | 0.6 | | | 0.2 | | | 0.2 | | | 0.3 | | | 0.2 | | | 0.3 | |
Maintenance | | 2.4 | | | 0.6 | | | 0.4 | | | 0.2 | | | 0.4 | | | 0.2 | | | 0.3 | |
Regulatory Assets (a) | | (7.9) | | | — | | | (2.9) | | | (22.9) | | | 20.3 | | | — | | | 1.4 | |
Regulatory Liabilities (a) | | 123.6 | | | 0.5 | | | 28.9 | | | 1.9 | | | 5.9 | | | 40.2 | | | 38.5 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 265.5 | | | $ | 1.7 | | | $ | 27.0 | | | $ | (20.5) | | | $ | 26.9 | | | $ | 40.6 | | | $ | 40.5 | |
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
(b)Increase in amounts for the three and nine months ended September 30, 2022 are primarily due to increases in commodity prices for power and natural gas and an increase in value of FTRs.
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 line item on the statements of income as that of the associated risk being hedged. 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.
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 |
| | September 30, 2021 | | December 31, 2020 | | September 30, 2021 | | December 31, 2020 |
| | (in millions) |
Long-term Debt (a) (b) | | $ | (965.6) | | | $ | (995.9) | | | $ | (22.1) | | | $ | (51.7) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Carrying Amount of the Hedged Liabilities | | Cumulative Amount of Fair Value Hedging Adjustment Included in the Carrying Amount of the Hedged Liabilities |
| | September 30, 2022 | | December 31, 2021 | | September 30, 2022 | | December 31, 2021 |
| | (in millions) |
Long-term Debt (a) (b) | | $ | (849.1) | | | $ | (952.3) | | | $ | 95.7 | | | $ | (8.5) | |
(a)Amounts included on the balance sheetsBalance Sheet within Current and Noncurrent Liabilities line items Long-term Debt Due within One Year and Long-term Debt, respectively.
(b)Amounts include $(47)$(40) million and $(53)$(46) million as of September 30, 20212022 and December 31, 2020,2021, 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 September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Gain (Loss) on Interest Rate Contracts: | Gain (Loss) on Interest Rate Contracts: | | Gain (Loss) on Interest Rate Contracts: | |
Fair Value Hedging Instruments (a) | Fair Value Hedging Instruments (a) | $ | (0.1) | | | $ | — | | | $ | (23.8) | | | $ | 42.6 | | Fair Value Hedging Instruments (a) | $ | (36.0) | | | $ | (0.1) | | | $ | (98.4) | | | $ | (23.8) | |
Fair Value Portion of Long-term Debt (a) | Fair Value Portion of Long-term Debt (a) | 0.1 | | | — | | | 23.8 | | | (42.6) | | Fair Value Portion of Long-term Debt (a) | 36.0 | | | 0.1 | | | 98.4 | | | 23.8 | |
(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 (Applies to AEP, AEP Texas, APCo, I&M and SWEPCo)
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 nine months ended September 30, 20212022 and 2020,2021, AEP applied cash flow hedging to outstanding power derivatives and the Registrant Subsidiaries did not.
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 nine months ended September 30, 2022, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not. During the three months ended September 30, 2021, AEP applied cash flow hedging to outstanding interest rate derivatives and the Registrant Subsidiaries did not. During the three months ended September 30, 2020, AEP and APCo applied cash flow hedging to outstanding interest rate derivatives and the other Registrant Subsidiaries did not. During the nine months ended September 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.
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
| | | September 30, 2021 | | December 31, 2020 | | September 30, 2022 | | December 31, 2021 |
| | Commodity | | Interest Rate | | Commodity | | Interest Rate | | Commodity | | Interest Rate | | Commodity | | Interest Rate |
| | (in millions) | | (in millions) |
AOCI Gain (Loss) Net of Tax | AOCI Gain (Loss) Net of Tax | | $ | 283.9 | | | $ | (26.1) | | | $ | (60.6) | | | $ | (47.5) | | AOCI Gain (Loss) Net of Tax | | $ | 452.1 | | | $ | (2.6) | | | $ | 163.7 | | | $ | (21.3) | |
Portion Expected to be Reclassed to Net Income During the Next Twelve Months | Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | 56.5 | | | (2.6) | | | (27.1) | | | (5.7) | | Portion Expected to be Reclassed to Net Income During the Next Twelve Months | | 316.2 | | | (1.5) | | | 106.7 | | | (3.3) | |
As of September 30, 20212022 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 114102 months and 11199 months for commodity and interest rate hedges, respectively.
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets
| | | September 30, 2021 | | December 31, 2020 | | September 30, 2022 | | December 31, 2021 |
| | Interest Rate | | Interest Rate |
| | | Expected to be | | Expected to be | | | Expected to be | | Expected to be |
| | Reclassified to | | Reclassified to | | Reclassified to | | Reclassified to |
| | Net Income During | | Net Income During | | Net Income During | | Net Income During |
| | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next | | AOCI Gain (Loss) | | the Next |
Company | Company | | Net of Tax | | Twelve Months | | Net of Tax | | Twelve Months | Company | | Net of Tax | | Twelve Months | | Net of Tax | | Twelve Months |
| | | (in millions) | | | (in millions) |
AEP Texas | AEP Texas | | $ | (1.5) | | | $ | (1.1) | | | $ | (2.3) | | | $ | (1.1) | | AEP Texas | | $ | (0.5) | | | $ | (0.4) | | | $ | (1.3) | | | $ | (1.1) | |
APCo | APCo | | 7.7 | | | 0.8 | | | (0.8) | | | 0.4 | | APCo | | 6.9 | | | 0.8 | | | 7.5 | | | 0.8 | |
I&M | I&M | | (7.0) | | | (1.6) | | | (8.3) | | | (1.6) | | I&M | | (5.5) | | | (1.0) | | | (6.7) | | | (1.6) | |
| PSO | | — | | | — | | | 0.1 | | | 0.1 | | |
| SWEPCo | SWEPCo | | 0.8 | | | (0.4) | | | (0.3) | | | (1.5) | | SWEPCo | | 1.2 | | | 0.2 | | | 1.2 | | | 0.1 | |
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.
Collateral Triggering EventsCredit-Risk-Related Contingent Features
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 derivative contracts with collateral triggering events in a net liability position as of September 30, 2021, with a total exposure of $25 million.$10 million and $9 million as of September 30, 2022 and December 31, 2021, respectively. The Registrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability position as of September 30, 2022 and December 31, 2021.
Cross-Acceleration Triggers
Certain interest rate derivative contracts contain cross-acceleration provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-acceleration provisions could be triggered if there was a non-performance event by the Registrants under any of their outstanding debt of at least $50 million and the lender on that debt has accelerated the entire repayment obligation. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-acceleration provisions in contracts. AEP had derivative contracts with cross-acceleration provisions in a net liability position of $135 million and $40 million as of September 30, 2022 and December 31, 2021, respectively. There was no cash collateral posted as of September 30, 2022 and December 31, 2021, respectively. If a cross-acceleration provision would have been triggered, settlement at fair value would have been required. The RegistrantsRegistrant Subsidiaries had no derivative contracts with collateral triggering events in a net liability positioncross-acceleration provisions outstanding as of September 30, 2022 and December 31, 2020.2021.
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 theseAEP had derivative liabilities subject to cross-default provisions prior to considerationin a net liability position of $260 million and $76 million as of September 30, 2022 and December 31, 2021, respectively, after considering contractual netting arrangements, (b) the amount that the exposure has been reduced by casharrangements. Cash collateral posted as of September 30, 2022 and (c) ifDecember 31, 2021 was not material. If a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements:
| | | | | | | | | | | | | | | | | | | | |
| | September 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 | | $ | 128.2 | | | $ | — | | | $ | 95.8 | |
APCo | | 1.0 | | | — | | | — | |
I&M | | 0.6 | | | — | | | — | |
| | | | | | |
| | | | | | |
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 | |
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 $30 millionwould have been required. The Registrant Subsidiaries’ derivative contracts with cross-default provisions outstanding as of September 30, 2021, and common share warrants. AEP recorded an unrealized gain (loss) of $(16) million and $22 million associated with the common shares for the three and nine months ended September 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 September 30, 20212022 and December 31, 2020, the warrants2021 were valued at $16 million and $32 million, respectively, and were recorded in Deferred Charges and Other Noncurrent Assets on AEP’s balance sheets. AEP recognized an unrealized loss of $10 million and $16 million associated with the warrants for the three and nine months ended September 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 September 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 September 30, 2021. The common shares are categorized as Level 1 based on the observable publicly traded stock price. See “Fair Value Measurements of Financial Assets and Liabilities” section of Note 10 for additional information.not material.
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.
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:
| | | September 30, 2021 | | December 31, 2020 | | September 30, 2022 | | December 31, 2021 |
Company | Company | | Book Value | | Fair Value | | Book Value | | Fair Value | Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | | (in millions) | | | (in millions) |
AEP (a)(c) | AEP (a)(c) | | $ | 34,578.3 | | | $ | 38,925.1 | | | $ | 31,072.5 | | | $ | 37,457.0 | | AEP (a)(c) | | $ | 35,050.1 | | | $ | 30,352.7 | | | $ | 33,454.5 | | | $ | 37,564.7 | |
AEP Texas | AEP Texas | | 5,216.1 | | | 5,763.9 | | | 4,820.4 | | | 5,682.6 | | AEP Texas | | 5,693.9 | | | 4,889.7 | | | 5,180.8 | | | 5,663.8 | |
AEPTCo | AEPTCo | | 4,393.4 | | | 5,074.5 | | | 3,948.5 | | | 4,984.3 | | AEPTCo | | 4,886.6 | | | 3,926.3 | | | 4,343.9 | | | 4,968.2 | |
APCo | APCo | | 4,937.8 | | | 6,067.0 | | | 4,834.1 | | | 6,391.8 | | APCo | | 5,509.8 | | | 4,994.1 | | | 4,938.9 | | | 6,037.1 | |
I&M | I&M | | 3,231.1 | | | 3,790.5 | | | 3,029.9 | | | 3,775.3 | | I&M | | 3,206.7 | | | 2,846.2 | | | 3,195.0 | | | 3,748.0 | |
OPCo | OPCo | | 3,468.1 | | | 3,948.6 | | | 2,430.2 | | | 3,154.9 | | OPCo | | 2,969.9 | | | 2,442.0 | | | 2,968.5 | | | 3,437.5 | |
PSO | PSO | | 1,913.3 | | | 2,169.2 | | | 1,373.8 | | | 1,732.1 | | PSO | | 1,913.6 | | | 1,616.9 | | | 1,913.5 | | | 2,163.7 | |
SWEPCo | SWEPCo | | 3,129.9 | | | 3,534.0 | | | 2,636.4 | | | 3,210.1 | | SWEPCo | | 3,392.4 | | | 2,797.3 | | | 3,395.2 | | | 3,792.9 | |
(a)The fair value amounts include debt related to AEP’s Equity Units and had a fair value of $1.6 billion$842 million and $1.7 billion as of September 30, 20212022 and December 31, 2020,2021, respectively. See “Equity Units” section of Note 12 for additional information.
(b)The book value amounts exclude Long-term Debt of $1.2 billion and $1.1 billion as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(c)The fair value amounts exclude Long-term Debt of $1.1 billion and $1.2 billion as of September 30, 2022 and December 31, 2021, respectively, related to KPCo. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
Fair Value Measurements of Other Temporary Investments and Restricted Cash (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:Investments and Restricted Cash:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
Restricted Cash and Other Cash Deposits (a) | | $ | 77.3 | | | $ | — | | | $ | — | | | $ | 77.3 | |
Fixed Income Securities – Mutual Funds (b) | | 141.8 | | | 1.8 | | | — | | | 143.6 | |
Equity Securities – Mutual Funds | | 19.4 | | | 32.1 | | | — | | | 51.5 | |
Total Other Temporary Investments | | $ | 238.5 | | | $ | 33.9 | | | $ | — | | | $ | 272.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2022 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments and Restricted Cash | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
Restricted Cash (a) | | $ | 55.1 | | | $ | — | | | $ | — | | | $ | 55.1 | |
Other Cash Deposits | | 18.1 | | | — | | | — | | | 18.1 | |
Fixed Income Securities – Mutual Funds (b) | | 155.1 | | | — | | | (9.7) | | | 145.4 | |
Equity Securities – Mutual Funds | | 20.4 | | | 18.6 | | | (0.3) | | | 38.7 | |
Total Other Temporary Investments and Restricted Cash | | $ | 248.7 | | | $ | 18.6 | | | $ | (10.0) | | | $ | 257.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2021 |
| | | | Gross | | Gross | | |
| | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments and Restricted Cash | | Cost | | Gains | | Losses | | Value |
| | (in millions) |
Restricted Cash (a) | | $ | 48.0 | | | $ | — | | | $ | — | | | $ | 48.0 | |
Other Cash Deposits | | 10.0 | | | — | | | — | | | 10.0 | |
Fixed Income Securities – Mutual Funds (b) | | 154.3 | | | 0.5 | | | — | | | 154.8 | |
Equity Securities – Mutual Funds | | 19.7 | | | 35.9 | | | — | | | 55.6 | |
Total Other Temporary Investments and Restricted Cash | | $ | 232.0 | | | $ | 36.4 | | | $ | — | | | $ | 268.4 | |
(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.
The following table provides the activity for fixed income and equity securities within Other Temporary Investments:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) | | (in millions) |
Proceeds from Investment Sales | Proceeds from Investment Sales | $ | 6.0 | | | $ | 5.1 | | | $ | 15.1 | | | $ | 35.9 | | Proceeds from Investment Sales | $ | — | | | $ | 6.0 | | | $ | 15.0 | | | $ | 15.1 | |
Purchases of Investments | Purchases of Investments | 12.9 | | | 22.5 | | | 26.0 | | | 39.5 | | Purchases of Investments | 11.8 | | | 12.9 | | | 13.4 | | | 26.0 | |
Gross Realized Gains on Investment Sales | Gross Realized Gains on Investment Sales | 2.4 | | | 0.2 | | | 3.6 | | | 2.4 | | Gross Realized Gains on Investment Sales | — | | | 2.4 | | | 3.6 | | | 3.6 | |
Gross Realized Losses on Investment Sales | Gross Realized Losses on Investment Sales | — | | | — | | | — | | | 0.2 | | Gross Realized Losses on Investment Sales | — | | | — | | | 0.5 | | | — | |
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.
The following is a summary of nuclear trust fund investments:
| | | September 30, 2021 | | December 31, 2020 | | September 30, 2022 | | December 31, 2021 |
| | | Gross | | Other-Than- | | | Gross | | Other-Than- | | | Gross | | Other-Than- | | | Gross | | Other-Than- |
| | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary |
| | Value | | Gains | | Impairments | | Value | | Gains | | Impairments | | Value | | Gains | | Impairments | | Value | | Gains | | Impairments |
| | (in millions) | | (in millions) |
Cash and Cash Equivalents | Cash and Cash Equivalents | $ | 63.9 | | | $ | — | | | $ | — | | | $ | 25.8 | | | $ | — | | | $ | — | | Cash and Cash Equivalents | $ | 20.8 | | | $ | — | | | $ | — | | | $ | 84.7 | | | $ | — | | | $ | — | |
Fixed Income Securities: | Fixed Income Securities: | | Fixed Income Securities: | |
United States Government | United States Government | 1,135.3 | | | 66.9 | | | (6.8) | | | 1,025.6 | | | 98.5 | | | (7.1) | | United States Government | 1,115.2 | | | (26.2) | | | (39.8) | | | 1,156.4 | | | 66.3 | | | (7.9) | |
Corporate Debt | Corporate Debt | 86.6 | | | 6.9 | | | (2.0) | | | 86.3 | | | 9.6 | | | (1.7) | | Corporate Debt | 60.9 | | | (7.7) | | | (1.2) | | | 76.7 | | | 6.7 | | | (2.1) | |
State and Local Government | State and Local Government | 36.8 | | | 0.3 | | | (0.2) | | | 114.3 | | | 0.9 | | | (0.4) | | State and Local Government | 7.0 | | | — | | | (0.1) | | | 7.3 | | | 0.4 | | | (0.1) | |
Subtotal Fixed Income Securities | Subtotal Fixed Income Securities | 1,258.7 | | | 74.1 | | | (9.0) | | | 1,226.2 | | | 109.0 | | | (9.2) | | Subtotal Fixed Income Securities | 1,183.1 | | | (33.9) | | | (41.1) | | | 1,240.4 | | | 73.4 | | | (10.1) | |
Equity Securities - Domestic (a) | Equity Securities - Domestic (a) | 2,287.2 | | | 1,652.8 | | | — | | | 2,054.7 | | | 1,400.8 | | | — | | Equity Securities - Domestic (a) | 1,926.6 | | | 1,279.1 | | | — | | | 2,541.9 | | | 1,901.3 | | | — | |
Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | $ | 3,609.8 | | | $ | 1,726.9 | | | $ | (9.0) | | | $ | 3,306.7 | | | $ | 1,509.8 | | | $ | (9.2) | | Spent Nuclear Fuel and Decommissioning Trusts | $ | 3,130.5 | | | $ | 1,245.2 | | | $ | (41.1) | | | $ | 3,867.0 | | | $ | 1,974.7 | | | $ | (10.1) | |
(a)Amount reported as Gross Unrealized Gains includes unrealized gains of $1.7$1.3 billion and $1.4$1.9 billion and unrealized losses of $4$14 million and $9$4 million as of September 30, 20212022 and December 31, 2020,2021, respectively.
The following table provides the securities activity within the decommissioning and SNF trusts:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2021 | | 2020 | | 2021 | | 2020 | | | 2022 | | 2021 | | 2022 | | 2021 |
| | | (in millions) | | | (in millions) |
Proceeds from Investment Sales | Proceeds from Investment Sales | | $ | 433.9 | | | $ | 316.6 | | | $ | 1,556.6 | | | $ | 1,257.1 | | Proceeds from Investment Sales | | $ | 588.5 | | | $ | 433.9 | | | $ | 1,818.4 | | | $ | 1,556.6 | |
Purchases of Investments | Purchases of Investments | | 436.6 | | | 318.6 | | | 1,586.3 | | | 1,290.0 | | Purchases of Investments | | 601.6 | | | 436.6 | | | 1,854.8 | | | 1,586.3 | |
Gross Realized Gains on Investment Sales | Gross Realized Gains on Investment Sales | | 9.6 | | | 3.4 | | | 98.3 | | | 25.4 | | Gross Realized Gains on Investment Sales | | 24.6 | | | 9.6 | | | 41.3 | | | 98.3 | |
Gross Realized Losses on Investment Sales | Gross Realized Losses on Investment Sales | | 7.0 | | | 0.5 | | | 12.5 | | | 25.2 | | Gross Realized Losses on Investment Sales | | 8.4 | | | 7.0 | | | 33.5 | | | 12.5 | |
The base cost of fixed income securities was $1.2 billion and $1.1$1.2 billion as of September 30, 20212022 and December 31, 2020,2021, respectively. The base cost of equity securities was $634$647 million and $654$641 million as of September 30, 20212022 and December 31, 2020,2021, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 20212022 was as follows:
| | | | | |
| Fair Value of Fixed |
| Income Securities |
| (in millions) |
Within 1 year | $ | 292.9369.4 | |
After 1 year through 5 years | 433.4393.8 | |
After 5 years through 10 years | 251.5229.0 | |
After 10 years | 280.9190.9 | |
Total | $ | 1,258.71,183.1 | |
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
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Other Temporary Investments | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 66.1 | | | $ | — | | | $ | — | | | $ | 11.2 | | | $ | 77.3 | | |
Other Temporary Investments and Restricted Cash | | Other Temporary Investments and Restricted Cash | |
Restricted Cash | | Restricted Cash | | $ | 55.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 55.1 | |
Other Cash Deposits (a) | | Other Cash Deposits (a) | | — | | | — | | | — | | | 18.1 | | | 18.1 | |
Fixed Income Securities – Mutual Funds | Fixed Income Securities – Mutual Funds | | 143.6 | | | — | | | — | | | — | | | 143.6 | | Fixed Income Securities – Mutual Funds | | 145.4 | | | — | | | — | | | — | | | 145.4 | |
Equity Securities – Mutual Funds (b) | Equity Securities – Mutual Funds (b) | | 51.5 | | | — | | | — | | | — | | | 51.5 | | Equity Securities – Mutual Funds (b) | | 38.7 | | | — | | | — | | | — | | | 38.7 | |
Total Other Temporary Investments | | 261.2 | | | — | | | — | | | 11.2 | | | 272.4 | | |
Total Other Temporary Investments and Restricted Cash | | Total Other Temporary Investments and Restricted Cash | | 239.2 | | | — | | | — | | | 18.1 | | | 257.3 | |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (d) | | 16.9 | | | 1,090.7 | | | 221.9 | | | (1,054.0) | | | 275.5 | | |
Risk Management Commodity Contracts (c) (d) (i) | | Risk Management Commodity Contracts (c) (d) (i) | | 31.7 | | | 1,650.1 | | | 467.7 | | | (1,910.8) | | | 238.7 | |
Cash Flow Hedges: | Cash Flow Hedges: | | Cash Flow Hedges: | |
Commodity Hedges (c) | Commodity Hedges (c) | | — | | | 367.3 | | | 31.3 | | | (34.9) | | | 363.7 | | Commodity Hedges (c) | | — | | | 612.1 | | | 45.3 | | | (68.9) | | | 588.5 | |
Interest Rate Hedges | Interest Rate Hedges | | — | | | 4.9 | | | — | | | — | | | 4.9 | | Interest Rate Hedges | | — | | | 9.3 | | | — | | | (0.5) | | | 8.8 | |
Fair Value Hedges | | — | | | 3.4 | | | — | | | — | | | 3.4 | | |
| Total Risk Management Assets | Total Risk Management Assets | | 16.9 | | | 1,466.3 | | | 253.2 | | | (1,088.9) | | | 647.5 | | Total Risk Management Assets | | 31.7 | | | 2,271.5 | | | 513.0 | | | (1,980.2) | | | 836.0 | |
| Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | Spent Nuclear Fuel and Decommissioning Trusts | |
Cash and Cash Equivalents (e) | Cash and Cash Equivalents (e) | | 56.0 | | | — | | | — | | | 7.9 | | | 63.9 | | Cash and Cash Equivalents (e) | | 10.4 | | | — | | | — | | | 10.4 | | | 20.8 | |
Fixed Income Securities: | Fixed Income Securities: | | Fixed Income Securities: | |
United States Government | United States Government | | — | | | 1,135.3 | | | — | | | — | | | 1,135.3 | | United States Government | | — | | | 1,115.2 | | | — | | | — | | | 1,115.2 | |
Corporate Debt | Corporate Debt | | — | | | 86.6 | | | — | | | — | | | 86.6 | | Corporate Debt | | — | | | 60.9 | | | — | | | — | | | 60.9 | |
State and Local Government | State and Local Government | | — | | | 36.8 | | | — | | | — | | | 36.8 | | State and Local Government | | — | | | 7.0 | | | — | | | — | | | 7.0 | |
Subtotal Fixed Income Securities | Subtotal Fixed Income Securities | | — | | | 1,258.7 | | | — | | | — | | | 1,258.7 | | Subtotal Fixed Income Securities | | — | | | 1,183.1 | | | — | | | — | | | 1,183.1 | |
Equity Securities – Domestic (b) | Equity Securities – Domestic (b) | | 2,287.2 | | | — | | | — | | | — | | | 2,287.2 | | Equity Securities – Domestic (b) | | 1,926.6 | | | — | | | — | | | — | | | 1,926.6 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,343.2 | | | 1,258.7 | | | — | | | 7.9 | | | 3,609.8 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,937.0 | | | 1,183.1 | | | — | | | 10.4 | | | 3,130.5 | |
| Other Investments (h) | | 30.3 | | | 15.9 | | | — | | | — | | | 46.2 | | |
| | Total Assets | Total Assets | | $ | 2,651.6 | | | $ | 2,740.9 | | | $ | 253.2 | | | $ | (1,069.8) | | | $ | 4,575.9 | | Total Assets | | $ | 2,207.9 | | | $ | 3,454.6 | | | $ | 513.0 | | | $ | (1,951.7) | | | $ | 4,223.8 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (d) | | $ | 8.4 | | | $ | 923.3 | | | $ | 124.1 | | | $ | (782.6) | | | $ | 273.2 | | |
Risk Management Commodity Contracts (c) (d) (j) | | Risk Management Commodity Contracts (c) (d) (j) | | $ | 20.1 | | | $ | 1,227.7 | | | $ | 240.5 | | | $ | (1,063.9) | | | $ | 424.4 | |
Cash Flow Hedges: | Cash Flow Hedges: | | Cash Flow Hedges: | |
Commodity Hedges (c) | Commodity Hedges (c) | | — | | | 38.9 | | | 0.1 | | | (34.9) | | | 4.1 | | Commodity Hedges (c) | | — | | | 83.7 | | | 0.9 | | | (68.9) | | | 15.7 | |
| Interest Rate Hedges | | Interest Rate Hedges | | — | | | 0.5 | | | — | | | (0.5) | | | — | |
Fair Value Hedges | Fair Value Hedges | | — | | | 28.8 | | | — | | | — | | | 28.8 | | Fair Value Hedges | | — | | | 135.4 | | | — | | | — | | | 135.4 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | | $ | 8.4 | | | $ | 991.0 | | | $ | 124.2 | | | $ | (817.5) | | | $ | 306.1 | | Total Risk Management Liabilities | | $ | 20.1 | | | $ | 1,447.3 | | | $ | 241.4 | | | $ | (1,133.3) | | | $ | 575.5 | |
AEP
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Other Temporary Investments | | |
Restricted Cash and Other Cash Deposits (a) | | $ | 57.8 | | | $ | — | | | $ | — | | | $ | 10.5 | | | $ | 68.3 | | |
Other Temporary Investments and Restricted Cash | | Other Temporary Investments and Restricted Cash | |
Restricted Cash | | Restricted Cash | | $ | 48.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | 48.0 | |
Other Cash Deposits (a) | | Other Cash Deposits (a) | | — | | | — | | | — | | | 10.0 | | | 10.0 | |
Fixed Income Securities – Mutual Funds | Fixed Income Securities – Mutual Funds | | 123.5 | | | — | | | — | | | — | | | 123.5 | | Fixed Income Securities – Mutual Funds | | 154.8 | | | — | | | — | | | — | | | 154.8 | |
Equity Securities – Mutual Funds (b) | Equity Securities – Mutual Funds (b) | | 54.6 | | | — | | | — | | | — | | | 54.6 | | Equity Securities – Mutual Funds (b) | | 55.6 | | | — | | | — | | | — | | | 55.6 | |
Total Other Temporary Investments | | 235.9 | | | — | | | — | | | 10.5 | | | 246.4 | | |
Total Other Temporary Investments and Restricted Cash | | Total Other Temporary Investments and Restricted Cash | | 258.4 | | | — | | | — | | | 10.0 | | | 268.4 | |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (f) | | 0.9 | | | 258.8 | | | 252.4 | | | (190.0) | | | 322.1 | | |
Risk Management Commodity Contracts (c) (f) (i) | | Risk Management Commodity Contracts (c) (f) (i) | | 7.4 | | | 648.5 | | | 226.3 | | | (642.4) | | | 239.8 | |
Cash Flow Hedges: | Cash Flow Hedges: | | Cash Flow Hedges: | |
Commodity Hedges (c) | Commodity Hedges (c) | | — | | | 34.4 | | | 3.9 | | | (28.5) | | | 9.8 | | Commodity Hedges (c) | | — | | | 242.9 | | | 19.2 | | | (41.7) | | | 220.4 | |
Interest Rate Hedges | | — | | | 2.4 | | | — | | | — | | | 2.4 | | |
| Fair Value Hedges | Fair Value Hedges | | — | | | 2.6 | | | — | | | — | | | 2.6 | | Fair Value Hedges | | — | | | 1.2 | | | — | | | — | | | 1.2 | |
Total Risk Management Assets | Total Risk Management Assets | | 0.9 | | | 298.2 | | | 256.3 | | | (218.5) | | | 336.9 | | Total Risk Management Assets | | 7.4 | | | 892.6 | | | 245.5 | | | (684.1) | | | 461.4 | |
| Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | Spent Nuclear Fuel and Decommissioning Trusts | |
Cash and Cash Equivalents (e) | Cash and Cash Equivalents (e) | | 16.8 | | | — | | | — | | | 9.0 | | | 25.8 | | Cash and Cash Equivalents (e) | | 77.7 | | | — | | | — | | | 7.0 | | | 84.7 | |
Fixed Income Securities: | Fixed Income Securities: | | Fixed Income Securities: | |
United States Government | United States Government | | — | | | 1,025.6 | | | — | | | — | | | 1,025.6 | | United States Government | | — | | | 1,156.4 | | | — | | | — | | | 1,156.4 | |
Corporate Debt | Corporate Debt | | — | | | 86.3 | | | — | | | — | | | 86.3 | | Corporate Debt | | — | | | 76.7 | | | — | | | — | | | 76.7 | |
State and Local Government | State and Local Government | | — | | | 114.3 | | | — | | | — | | | 114.3 | | State and Local Government | | — | | | 7.3 | | | — | | | — | | | 7.3 | |
Subtotal Fixed Income Securities | Subtotal Fixed Income Securities | | — | | | 1,226.2 | | | — | | | — | | | 1,226.2 | | Subtotal Fixed Income Securities | | — | | | 1,240.4 | | | — | | | — | | | 1,240.4 | |
Equity Securities – Domestic (b) | Equity Securities – Domestic (b) | | 2,054.7 | | | — | | | — | | | — | | | 2,054.7 | | Equity Securities – Domestic (b) | | 2,541.9 | | | — | | | — | | | — | | | 2,541.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,071.5 | | | 1,226.2 | | | — | | | 9.0 | | | 3,306.7 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,619.6 | | | 1,240.4 | | | — | | | 7.0 | | | 3,867.0 | |
| Other Investments (h) | Other Investments (h) | | — | | | — | | | 31.8 | | | — | | | 31.8 | | Other Investments (h) | | 28.8 | | | 14.9 | | | — | | | — | | | 43.7 | |
| Total Assets | Total Assets | | $ | 2,308.3 | | | $ | 1,524.4 | | | $ | 288.1 | | | $ | (199.0) | | | $ | 3,921.8 | | Total Assets | | $ | 2,914.2 | | | $ | 2,147.9 | | | $ | 245.5 | | | $ | (667.1) | | | $ | 4,640.5 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (f) | | $ | 0.9 | | | $ | 244.2 | | | $ | 167.2 | | | $ | (193.4) | | | $ | 218.9 | | |
Risk Management Commodity Contracts (c) (f) (j) | | Risk Management Commodity Contracts (c) (f) (j) | | $ | 5.3 | | | $ | 485.0 | | | $ | 147.6 | | | $ | (383.2) | | | $ | 254.7 | |
Cash Flow Hedges: | Cash Flow Hedges: | | Cash Flow Hedges: | |
Commodity Hedges (c) | Commodity Hedges (c) | | — | | | 106.1 | | | 7.6 | | | (28.5) | | | 85.2 | | Commodity Hedges (c) | | — | | | 54.0 | | | 0.6 | | | (41.7) | | | 12.9 | |
Interest Rate Hedges | | — | | | 3.4 | | | — | | | — | | | 3.4 | | |
| Fair Value Hedges | Fair Value Hedges | | — | | | 4.1 | | | — | | | — | | | 4.1 | | Fair Value Hedges | | — | | | 38.1 | | | — | | | — | | | 38.1 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | | $ | 0.9 | | | $ | 357.8 | | | $ | 174.8 | | | $ | (221.9) | | | $ | 311.6 | | Total Risk Management Liabilities | | $ | 5.3 | | | $ | 577.1 | | | $ | 148.2 | | | $ | (424.9) | | | $ | 305.7 | |
AEP Texas
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Restricted Cash for Securitized Funding | Restricted Cash for Securitized Funding | | $ | 43.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | 43.9 | | Restricted Cash for Securitized Funding | | $ | 47.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 47.7 | |
| Risk Management Assets | Risk Management Assets | | | | | | | | | | | Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) | Risk Management Commodity Contracts (c) | | — | | | 0.9 | | | — | | | (0.9) | | | — | | Risk Management Commodity Contracts (c) | | — | | | 0.1 | | | — | | | 0.2 | | | 0.3 | |
| Total Assets | Total Assets | | $ | 43.9 | | | $ | 0.9 | | | $ | — | | | $ | (0.9) | | | $ | 43.9 | | Total Assets | | $ | 47.7 | | | $ | 0.1 | | | $ | — | | | $ | 0.2 | | | $ | 48.0 | |
| Liabilities: | | Liabilities: | |
| Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) | | Risk Management Commodity Contracts (c) | | $ | — | | | $ | 0.1 | | | $ | — | | | $ | — | | | $ | 0.1 | |
December 31, 20202021
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| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
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Restricted Cash for Securitized Funding | | $ | 28.7 | | | $ | — | | | $ | — | | | $ | — | | | $ | 28.7 | |
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Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | — | | | 0.4 | | | — | | | (0.4) | | | — | |
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Total Assets | | $ | 28.7 | | | $ | 0.4 | | | $ | — | | | $ | (0.4) | | | $ | 28.7 | |
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| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) |
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Restricted Cash for Securitized Funding | | $ | 30.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 30.4 | |
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Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) | | — | | | 0.6 | | | — | | | (0.6) | | | — | |
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Total Assets | | $ | 30.4 | | | $ | 0.6 | | | $ | — | | | $ | (0.6) | | | $ | 30.4 | |
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APCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Restricted Cash for Securitized Funding | Restricted Cash for Securitized Funding | | $ | 10.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | 10.1 | | Restricted Cash for Securitized Funding | | $ | 7.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | 7.4 | |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | — | | | 48.9 | | | 47.0 | | | (48.9) | | | 47.0 | | Risk Management Commodity Contracts (c) (g) | | — | | | 0.9 | | | 106.7 | | | (0.8) | | | 106.8 | |
| | Total Assets | Total Assets | | $ | 10.1 | | | $ | 48.9 | | | $ | 47.0 | | | $ | (48.9) | | | $ | 57.1 | | Total Assets | | $ | 7.4 | | | $ | 0.9 | | | $ | 106.7 | | | $ | (0.8) | | | $ | 114.2 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 59.3 | | | $ | 1.1 | | | $ | (59.1) | | | $ | 1.3 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.7 | | | $ | 0.1 | | | $ | (0.8) | | | $ | — | |
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December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Restricted Cash for Securitized Funding | Restricted Cash for Securitized Funding | | $ | 16.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | 16.9 | | Restricted Cash for Securitized Funding | | $ | 17.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | 17.6 | |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | — | | | 19.4 | | | 19.9 | | | (19.2) | | | 20.1 | | Risk Management Commodity Contracts (c) (g) | | — | | | 5.8 | | | 42.0 | | | (5.8) | | | 42.0 | |
Cash Flow Hedges: | | |
Interest Rate Hedges | | — | | | 2.4 | | | — | | | — | | | 2.4 | | |
Total Risk Management Assets | | — | | | 21.8 | | | 19.9 | | | (19.2) | | | 22.5 | | |
| | Total Assets | Total Assets | | $ | 16.9 | | | $ | 21.8 | | | $ | 19.9 | | | $ | (19.2) | | | $ | 39.4 | | Total Assets | | $ | 17.6 | | | $ | 5.8 | | | $ | 42.0 | | | $ | (5.8) | | | $ | 59.6 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 19.5 | | | $ | 0.6 | | | $ | (18.8) | | | $ | 1.3 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 7.2 | | | $ | 0.3 | | | $ | (6.7) | | | $ | 0.8 | |
Cash Flow Hedges: | | |
Interest Rate Hedges | | — | | | 3.4 | | | — | | | — | | | 3.4 | | |
Total Risk Management Liabilities | | $ | — | | | $ | 22.9 | | | $ | 0.6 | | | $ | (18.8) | | | $ | 4.7 | | |
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I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 30.9 | | | $ | 7.0 | | | $ | (32.4) | | | $ | 5.5 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 2.4 | | | $ | 10.3 | | | $ | (1.1) | | | $ | 11.6 | |
| Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | Spent Nuclear Fuel and Decommissioning Trusts | |
Cash and Cash Equivalents (e) | Cash and Cash Equivalents (e) | | 56.0 | | | — | | | — | | | 7.9 | | | 63.9 | | Cash and Cash Equivalents (e) | | 10.4 | | | — | | | — | | | 10.4 | | | 20.8 | |
Fixed Income Securities: | Fixed Income Securities: | | Fixed Income Securities: | |
United States Government | United States Government | | — | | | 1,135.3 | | | — | | | — | | | 1,135.3 | | United States Government | | — | | | 1,115.2 | | | — | | | — | | | 1,115.2 | |
Corporate Debt | Corporate Debt | | — | | | 86.6 | | | — | | | — | | | 86.6 | | Corporate Debt | | — | | | 60.9 | | | — | | | — | | | 60.9 | |
State and Local Government | State and Local Government | | — | | | 36.8 | | | — | | | — | | | 36.8 | | State and Local Government | | — | | | 7.0 | | | — | | | — | | | 7.0 | |
Subtotal Fixed Income Securities | Subtotal Fixed Income Securities | | — | | | 1,258.7 | | | — | | | — | | | 1,258.7 | | Subtotal Fixed Income Securities | | — | | | 1,183.1 | | | — | | | — | | | 1,183.1 | |
Equity Securities - Domestic (b) | Equity Securities - Domestic (b) | | 2,287.2 | | | — | | | — | | | — | | | 2,287.2 | | Equity Securities - Domestic (b) | | 1,926.6 | | | — | | | — | | | — | | | 1,926.6 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,343.2 | | | 1,258.7 | | | — | | | 7.9 | | | 3,609.8 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 1,937.0 | | | 1,183.1 | | | — | | | 10.4 | | | 3,130.5 | |
| Total Assets | Total Assets | | $ | 2,343.2 | | | $ | 1,289.6 | | | $ | 7.0 | | | $ | (24.5) | | | $ | 3,615.3 | | Total Assets | | $ | 1,937.0 | | | $ | 1,185.5 | | | $ | 10.3 | | | $ | 9.3 | | | $ | 3,142.1 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 48.3 | | | $ | 3.7 | | | $ | (49.5) | | | $ | 2.5 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.5 | | | $ | 0.7 | | | $ | (1.2) | | | $ | — | |
December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 15.1 | | | $ | 2.5 | | | $ | (13.9) | | | $ | 3.7 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 3.8 | | | $ | 7.6 | | | $ | (8.1) | | | $ | 3.3 | |
| Spent Nuclear Fuel and Decommissioning Trusts | Spent Nuclear Fuel and Decommissioning Trusts | | Spent Nuclear Fuel and Decommissioning Trusts | |
Cash and Cash Equivalents (e) | Cash and Cash Equivalents (e) | | 16.8 | | | — | | | — | | | 9.0 | | | 25.8 | | Cash and Cash Equivalents (e) | | 77.7 | | | — | | | — | | | 7.0 | | | 84.7 | |
Fixed Income Securities: | Fixed Income Securities: | | Fixed Income Securities: | |
United States Government | United States Government | | — | | | 1,025.6 | | | — | | | — | | | 1,025.6 | | United States Government | | — | | | 1,156.4 | | | — | | | — | | | 1,156.4 | |
Corporate Debt | Corporate Debt | | — | | | 86.3 | | | — | | | — | | | 86.3 | | Corporate Debt | | — | | | 76.7 | | | — | | | — | | | 76.7 | |
State and Local Government | State and Local Government | | — | | | 114.3 | | | — | | | — | | | 114.3 | | State and Local Government | | — | | | 7.3 | | | — | | | — | | | 7.3 | |
Subtotal Fixed Income Securities | Subtotal Fixed Income Securities | | — | | | 1,226.2 | | | — | | | — | | | 1,226.2 | | Subtotal Fixed Income Securities | | — | | | 1,240.4 | | | — | | | — | | | 1,240.4 | |
Equity Securities - Domestic (b) | Equity Securities - Domestic (b) | | 2,054.7 | | | — | | | — | | | — | | | 2,054.7 | | Equity Securities - Domestic (b) | | 2,541.9 | | | — | | | — | | | — | | | 2,541.9 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,071.5 | | | 1,226.2 | | | — | | | 9.0 | | | 3,306.7 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 2,619.6 | | | 1,240.4 | | | — | | | 7.0 | | | 3,867.0 | |
| Total Assets | Total Assets | | $ | 2,071.5 | | | $ | 1,241.3 | | | $ | 2.5 | | | $ | (4.9) | | | $ | 3,310.4 | | Total Assets | | $ | 2,619.6 | | | $ | 1,244.2 | | | $ | 7.6 | | | $ | (1.1) | | | $ | 3,870.3 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 12.0 | | | $ | 0.4 | | | $ | (12.2) | | | $ | 0.2 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 6.7 | | | $ | 8.3 | | | $ | (10.0) | | | $ | 5.0 | |
OPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Risk Management Assets | Risk Management Assets | | | | | | | | | | | Risk Management Assets | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.7 | | | $ | — | | | $ | (0.7) | | | $ | — | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.1 | | | $ | — | | | $ | 2.0 | | | $ | 2.1 | |
| | Liabilities: | Liabilities: | | | Liabilities: | | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 90.4 | | | $ | — | | | $ | 90.4 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.1 | | | $ | 43.2 | | | $ | 1.8 | | | $ | 45.1 | |
December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | — | | | $ | (0.3) | | | $ | — | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.5 | | | $ | — | | | $ | (0.5) | | | $ | — | |
| | Liabilities: | Liabilities: | | | Liabilities: | | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 110.3 | | | $ | — | | | $ | 110.3 | | |
Risk Management Commodity Contracts (g) | | Risk Management Commodity Contracts (g) | | $ | — | | | $ | — | | | $ | 92.5 | | | $ | — | | | $ | 92.5 | |
PSO
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 18.7 | | | $ | (0.5) | | | $ | 18.5 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 45.2 | | | $ | (0.7) | | | $ | 44.5 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 0.2 | | | $ | (0.2) | | | $ | — | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 0.8 | | | $ | (0.8) | | | $ | — | |
December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.2 | | | $ | 10.3 | | | $ | (0.2) | | | $ | 10.3 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 12.2 | | | $ | (0.4) | | | $ | 12.1 | |
| Liabilities: | | Liabilities: | |
| Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 3.7 | | | $ | 0.1 | | | $ | (0.1) | | | $ | 3.7 | |
SWEPCo
Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 20212022
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.4 | | | $ | 19.8 | | | $ | (0.6) | | | $ | 19.6 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.1 | | | $ | 37.0 | | | $ | (0.7) | | | $ | 36.4 | |
| | Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 0.2 | | | $ | (0.2) | | | $ | — | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 0.8 | | | $ | (0.8) | | | $ | — | |
December 31, 20202021
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | Assets: | | (in millions) | Assets: | | (in millions) |
| | Risk Management Assets | Risk Management Assets | | Risk Management Assets | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.1 | | | $ | 3.3 | | | $ | (0.2) | | | $ | 3.2 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 0.3 | | | $ | 11.0 | | | $ | (0.4) | | | $ | 10.9 | |
| | Liabilities: | Liabilities: | | Liabilities: | |
| Risk Management Liabilities | Risk Management Liabilities | | Risk Management Liabilities | |
Risk Management Commodity Contracts (c) (g) | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | — | | | $ | 1.7 | | | $ | — | | | $ | 1.7 | | Risk Management Commodity Contracts (c) (g) | | $ | — | | | $ | 2.1 | | | $ | 0.1 | | | $ | (0.1) | | | $ | 2.1 | |
(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 September 30, 2021 maturity2022 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 1 matures $2 million in 20212022 and $7$9 million in periods 2022-2024;2023-2025; Level 2 matures $20$47 million in 2021, $1122022, $363 million in periods 2022-2024, $222023-2025, $10 million in periods 2025-20262026-2027 and $13$3 million in periods 2027-2033;2028-2033; Level 3 matures $96$87 million in 2021,2022, $139 million in periods 2023-2025, $18 million in periods 2022-2024, $52026-2027 and $(2) million in periods 2025-2026 and $(21) million in periods 2027-2033.2028-2033. 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 maturity2021 maturities of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), were as follows: Level 21 matures $3$1 million in periods 2022-2024, $11 million in periods 2025-20262022 and $1 million in periods 2027-2033;2023-2025; Level 2 matures $42 million in 2022, $109 million in periods 2023-2025, $10 million in periods 2026-2027 and $3 million in periods 2028-2033; Level 3 matures $47$82 million in 2021, $372022, $10 million in periods 2022-2024, $142023-2025, $9 million in periods 2025-20262026-2027 and $(13)$(17) million in periods 2027-2033.2028-2033. 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 910 in the 2021 Annual Report for additional information.
(i)Amount excludes Risk Management Assets of $14.4 million and $6 million as of September 30, 2022 and December 31, 2021, respectively, classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(j)Amount excludes Risk Management Liabilities of $0 and $0.1 million as of September 30, 2022 and December 31, 2021, respectively, classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
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 September 30, 2022 | | Three Months Ended September 30, 2022 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Balance as of June 30, 2022 | | Balance as of June 30, 2022 | | $ | 270.4 | | | $ | 79.6 | | | $ | 9.8 | | | $ | (48.4) | | | $ | 64.5 | | | $ | 45.4 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 64.3 | | | 20.1 | | | 2.1 | | | 0.3 | | | 23.8 | | | 15.4 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (12.6) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 13.1 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | Settlements | | (138.3) | | | (34.6) | | | (4.8) | | | (1.1) | | | (49.1) | | | (31.6) | |
Transfers into Level 3 (d) (e) | | Transfers into Level 3 (d) (e) | | (0.5) | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | Transfers out of Level 3 (e) | | 3.5 | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 72.5 | | | 41.5 | | | 2.5 | | | 6.0 | | | 5.2 | | | 7.0 | |
Assets and Liabilities Held for Sale related to KPCo (g) | | Assets and Liabilities Held for Sale related to KPCo (g) | | (0.8) | | | — | | | — | | | — | | | — | | | — | |
Balance as of September 30, 2022 | | Balance as of September 30, 2022 | | $ | 271.6 | | | $ | 106.6 | | | $ | 9.6 | | | $ | (43.2) | | | $ | 44.4 | | | $ | 36.2 | |
| Three Months Ended September 30, 2021 | Three Months Ended September 30, 2021 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | Three Months Ended September 30, 2021 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) | | | (in millions) |
Balance as of June 30, 2021 | Balance as of June 30, 2021 | | $ | 101.2 | | | $ | 36.6 | | | $ | 7.3 | | | $ | (105.4) | | | $ | 22.9 | | | $ | 14.6 | | Balance as of June 30, 2021 | | $ | 101.2 | | | $ | 36.6 | | | $ | 7.3 | | | $ | (105.4) | | | $ | 22.9 | | | $ | 14.6 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 27.5 | | | 4.0 | | | 0.1 | | | 0.1 | | | 13.5 | | | 5.8 | | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 27.5 | | | 4.0 | | | 0.1 | | | 0.1 | | | 13.5 | | | 5.8 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 2.9 | | | — | | | — | | | — | | | — | | | — | | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 2.9 | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 17.8 | | | — | | | — | | | — | | | — | | | — | | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 17.8 | | | — | | | — | | | — | | | — | | | — | |
Settlements | Settlements | | (54.5) | | | (10.5) | | | (3.8) | | | 0.9 | | | (20.6) | | | (9.8) | | Settlements | | (54.5) | | | (10.5) | | | (3.8) | | | 0.9 | | | (20.6) | | | (9.8) | |
Transfers into Level 3 (d) (e) | Transfers into Level 3 (d) (e) | | (5.8) | | | — | | | — | | | — | | | — | | | — | | Transfers into Level 3 (d) (e) | | (5.8) | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | Transfers out of Level 3 (e) | | (4.1) | | | 0.1 | | | — | | | — | | | — | | | — | | Transfers out of Level 3 (e) | | (4.1) | | | 0.1 | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 44.0 | | | 15.7 | | | (0.3) | | | 14.0 | | | 2.7 | | | 9.0 | | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 44.0 | | | 15.7 | | | (0.3) | | | 14.0 | | | 2.7 | | | 9.0 | |
Balance as of September 30, 2021 | Balance as of September 30, 2021 | | $ | 129.0 | | | $ | 45.9 | | | $ | 3.3 | | | $ | (90.4) | | | $ | 18.5 | | | $ | 19.6 | | Balance as of September 30, 2021 | | $ | 129.0 | | | $ | 45.9 | | | $ | 3.3 | | | $ | (90.4) | | | $ | 18.5 | | | $ | 19.6 | |
| Three Months Ended September 30, 2020 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| | (in millions) | |
Balance as of June 30, 2020 | | $ | 111.6 | | | $ | 36.5 | | | $ | 4.5 | | | $ | (117.4) | | | $ | 23.8 | | | $ | 3.3 | | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 18.7 | | | 6.4 | | | 3.3 | | | — | | | 3.0 | | | 1.5 | | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | 6.5 | | | — | | | — | | | — | | | — | | | — | | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 2.6 | | | — | | | — | | | — | | | — | | | — | | |
Settlements | | (37.0) | | | (11.1) | | | (5.0) | | | 1.3 | | | (10.3) | | | (3.5) | | |
Transfers into Level 3 (d) (e) | | (1.0) | | | — | | | — | | | — | | | — | | | — | | |
Transfers out of Level 3 (e) | | 1.1 | | | — | | | — | | | — | | | — | | | — | | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 3.6 | | | (2.2) | | | 1.0 | | | 2.9 | | | (0.4) | | | 2.4 | | |
Balance as of September 30, 2020 | | $ | 106.1 | | | $ | 29.6 | | | $ | 3.8 | | | $ | (113.2) | | | $ | 16.1 | | | $ | 3.7 | | |
| Nine Months Ended September 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) | | 68.9 | | | 38.8 | | | 0.4 | | | 0.4 | | | 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) | | (64.1) | | | — | | | — | | | — | | | — | | | — | | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 35.5 | | | — | | | — | | | — | | | — | | | — | | |
Settlements | | (113.3) | | | (58.2) | | | (2.5) | | | 5.8 | | | (26.4) | | | (13.0) | | |
Transfers into Level 3 (d) (e) | | (0.2) | | | — | | | — | | | 0 | | — | | | — | | |
Transfers out of Level 3 (e) | | (26.2) | | | — | | | — | | | — | | | — | | | — | | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 115.1 | | | 46.0 | | | 3.3 | | | 13.7 | | | 18.5 | | | 21.5 | | |
Balance as of September 30, 2021 | | $ | 129.0 | | | $ | 45.9 | | | $ | 3.3 | | | $ | (90.4) | | | $ | 18.5 | | | $ | 19.6 | | |
|
| Nine Months Ended September 30, 2020 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Nine Months Ended September 30, 2022 | | Nine Months Ended September 30, 2022 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in millions) | | | (in millions) |
Balance as of December 31, 2019 | | $ | 109.9 | | | $ | 37.7 | | | $ | 5.8 | | | $ | (103.6) | | | $ | 15.8 | | | $ | 1.4 | | |
Balance as of December 31, 2021 | | Balance as of December 31, 2021 | | $ | 97.3 | | | $ | 41.7 | | | $ | (0.7) | | | $ | (92.5) | | | $ | 12.1 | | | $ | 10.9 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 39.6 | | | 13.1 | | | 2.4 | | | (1.2) | | | 11.9 | | | 2.8 | | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 69.3 | | | 3.0 | | | 3.7 | | | 4.6 | | | 24.2 | | | 35.8 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (2.4) | | | — | | | — | | | — | | | — | | | — | | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (44.6) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 21.7 | | | — | | | — | | | — | | | — | | | — | | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 29.4 | | | — | | | — | | | — | | | — | | | — | |
Settlements | Settlements | | (115.3) | | | (51.4) | | | (8.5) | | | 6.4 | | | (27.6) | | | (6.9) | | Settlements | | (153.8) | | | (44.7) | | | (3.0) | | | 0.2 | | | (36.3) | | | (45.0) | |
Transfers into Level 3 (d) (e) | Transfers into Level 3 (d) (e) | | (1.1) | | | — | | | — | | | — | | | — | | | — | | Transfers into Level 3 (d) (e) | | 1.7 | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | Transfers out of Level 3 (e) | | 5.6 | | | 0.7 | | | 0.4 | | | — | | | — | | | — | | Transfers out of Level 3 (e) | | 13.2 | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 48.1 | | | 29.5 | | | 3.7 | | | (14.8) | | | 16.0 | | | 6.4 | | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 267.6 | | | 106.6 | | | 9.6 | | | 44.5 | | | 44.4 | | | 34.5 | |
Balance as of September 30, 2020 | | $ | 106.1 | | | $ | 29.6 | | | $ | 3.8 | | | $ | (113.2) | | | $ | 16.1 | | | $ | 3.7 | | |
Assets and Liabilities Held for Sale related to KPCo (g) | | Assets and Liabilities Held for Sale related to KPCo (g) | | (8.5) | | | — | | | — | | | — | | | — | | | — | |
Balance as of September 30, 2022 | | Balance as of September 30, 2022 | | $ | 271.6 | | | $ | 106.6 | | | $ | 9.6 | | | $ | (43.2) | | | $ | 44.4 | | | $ | 36.2 | |
| Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 | | AEP | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in millions) |
Balance as of December 31, 2020 | | 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) | | Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | 68.9 | | | 38.8 | | | 0.4 | | | 0.4 | | | 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) | | Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | (64.1) | | | — | | | — | | | — | | | — | | | — | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (c) | | 35.5 | | | — | | | — | | | — | | | — | | | — | |
Settlements | | Settlements | | (113.3) | | | (58.2) | | | (2.5) | | | 5.8 | | | (26.4) | | | (13.0) | |
Transfers into Level 3 (d) (e) | | Transfers into Level 3 (d) (e) | | (0.2) | | | — | | | — | | | — | | | — | | | — | |
Transfers out of Level 3 (e) | | Transfers out of Level 3 (e) | | (26.2) | | | — | | | — | | | — | | | — | | | — | |
Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | Changes in Fair Value Allocated to Regulated Jurisdictions (f) | | 115.1 | | | 46.0 | | | 3.3 | | | 13.7 | | | 18.5 | | | 21.5 | |
Balance as of September 30, 2021 | | Balance as of September 30, 2021 | | $ | 129.0 | | | $ | 45.9 | | | $ | 3.3 | | | $ | (90.4) | | | $ | 18.5 | | | $ | 19.6 | |
(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)changes in fair value are recorded as regulatory assets/liabilities for net gains and as regulatory assets for net losses or accounts payable.
(g)Amount represents Risk Management Assets classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
AEP
Significant Unobservable Inputs
September 30, 20212022
| | | | | | Significant | | Input/Range | | | | | Significant | | Input/Range |
| | Fair Value | Valuation | | Unobservable | | | Weighted | | Fair Value | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average | | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | Energy Contracts | $ | 145.6 | | | $ | 117.3 | | | Discounted Cash Flow | | Forward Market Price (a) (c) | | $ | 0.10 | | | $ | 108.40 | | | $ | 35.57 | | Energy Contracts | $ | 292.7 | | | $ | 230.6 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | (4.31) | | | $ | 172.05 | | | $ | 49.58 | |
Natural Gas Contracts | Natural Gas Contracts | 9.0 | | | — | | | Discounted Cash Flow | | Forward Market Price (b) (c) | | 2.92 | | | 6.27 | | | 4.59 | | Natural Gas Contracts | 6.9 | | | — | | | Discounted Cash Flow | | Forward Market Price (b) | | 3.22 | | | 7.37 | | | 5.92 | |
FTRs | 98.6 | | | 6.9 | | | Discounted Cash Flow | | Forward Market Price (a) (c) | | (21.95) | | | 13.46 | | | 0.46 | | |
FTRs (d) (e) | | FTRs (d) (e) | 213.4 | | | 10.8 | | | Discounted Cash Flow | | Forward Market Price (a) | | (37.97) | | | 27.55 | | | 0.99 | |
| Total | Total | $ | 253.2 | | | $ | 124.2 | | | Total | $ | 513.0 | | | $ | 241.4 | | |
December 31, 20202021
| | | | | | Significant | | Input/Range | | | | | Significant | | Input/Range |
| | Fair Value | Valuation | | Unobservable | | | Weighted | | Fair Value | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average | | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts(f) | Energy Contracts(f) | $ | 213.5 | | | $ | 169.7 | | | Discounted Cash Flow | | Forward Market Price (a) (c) | | $ | 5.33 | | | $ | 100.47 | | | $ | 32.73 | | Energy Contracts(f) | $ | 164.4 | | | $ | 135.2 | | | Discounted Cash Flow | | Forward Market Price (a) | | $ | 10.30 | | | $ | 76.70 | | | $ | 37.11 | |
Natural Gas Contracts | Natural Gas Contracts | — | | | 1.7 | | | Discounted Cash Flow | | Forward Market Price (b) (c) | | 2.18 | | | 2.77 | | | 2.40 | | Natural Gas Contracts | 3.6 | | | — | | | Discounted Cash Flow | | Forward Market Price (b) | | 3.11 | | | 4.02 | | | 3.47 | |
FTRs | 42.8 | | | 3.4 | | | Discounted Cash Flow | | Forward Market Price (a) (c) | | (15.08) | | | 9.66 | | | 0.19 | | |
Other Investments | 31.8 | | | — | | | Black-Scholes Model | | Liquidity Adjustment (d) | | 10 | % | | 20 | % | | 15 | % | |
FTRs (g) (h) | | FTRs (g) (h) | 77.5 | | | 13.0 | | | Discounted Cash Flow | | Forward Market Price (a) | | (23.93) | | | 26.38 | | | 0.86 | |
| Total | Total | $ | 288.1 | | | $ | 174.8 | | | Total | $ | 245.5 | | | $ | 148.2 | | |
APCo
Significant Unobservable Inputs
September 30, 20212022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 0.2 | | | $ | 1.1 | | | Discounted Cash Flow | | Forward Market Price | | $ | 26.70 | | | $ | 87.14 | | | $ | 53.61 | |
FTRs | 46.8 | | | — | | | Discounted Cash Flow | | Forward Market Price | | 0.35 | | | 13.46 | | | 1.83 | |
Total | $ | 47.0 | | | $ | 1.1 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
FTRs | $ | 106.7 | | | $ | 0.1 | | | Discounted Cash Flow | | Forward Market Price | | $ | (2.01) | | | $ | 20.64 | | | $ | 3.75 | |
| | | | | | | | | | | | | |
December 31, 20202021
| | | | | Significant | | Input/Range | | | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | Weighted | | Fair Value | | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) | | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | Energy Contracts | $ | 1.0 | | | $ | 0.6 | | | Discounted Cash Flow | | Forward Market Price | | $ | 10.84 | | | $ | 41.09 | | | $ | 25.08 | | Energy Contracts | $ | — | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | 32.20 | | | $ | 56.54 | | | $ | 44.77 | |
FTRs | FTRs | 18.9 | | | — | | | Discounted Cash Flow | | Forward Market Price | | 0.04 | | | 5.61 | | | 1.13 | | FTRs | 42.0 | | | — | | | Discounted Cash Flow | | Forward Market Price | | (0.30) | | | 26.38 | | | 2.63 | |
Total | Total | $ | 19.9 | | | $ | 0.6 | | | Total | $ | 42.0 | | | $ | 0.3 | | |
I&M
Significant Unobservable Inputs
September 30, 20212022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | 0.2 | | | $ | 0.7 | | | Discounted Cash Flow | | Forward Market Price | | $ | 26.70 | | | $ | 87.14 | | | $ | 53.61 | |
FTRs | 6.8 | | | 3.0 | | | Discounted Cash Flow | | Forward Market Price | | (1.85) | | | 5.75 | | | 0.37 | |
Total | $ | 7.0 | | | $ | 3.7 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
FTRs | $ | 10.3 | | | $ | 0.7 | | | Discounted Cash Flow | | Forward Market Price | | $ | 0.21 | | | $ | 17.73 | | | $ | 1.61 | |
| | | | | | | | | | | | | |
December 31, 20202021
| | | Significant | | Input/Range | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | Weighted | | Fair Value | | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) | | Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Energy Contracts | Energy Contracts | $ | 0.6 | | | $ | 0.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | 10.84 | | | $ | 41.09 | | | $ | 25.08 | | Energy Contracts | $ | — | | | $ | 0.2 | | | Discounted Cash Flow | | Forward Market Price | | $ | 32.20 | | | $ | 56.54 | | | $ | 44.77 | |
FTRs | FTRs | 1.9 | | | 0.1 | | | Discounted Cash Flow | | Forward Market Price | | (1.96) | | | 3.69 | | | 0.33 | | FTRs | 7.6 | | | 8.1 | | | Discounted Cash Flow | | Forward Market Price | | (5.45) | | | 17.78 | | | (0.12) | |
Total | Total | $ | 2.5 | | | $ | 0.4 | | | Total | $ | 7.6 | | | $ | 8.3 | | |
OPCo
Significant Unobservable Inputs
September 30, 20212022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 90.4 | | | Discounted Cash Flow | | Forward Market Price | | $ | 9.89 | | | $ | 81.50 | | | $ | 32.40 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 43.2 | | | Discounted Cash Flow | | Forward Market Price | | $ | 1.65 | | | $ | 143.38 | | | $ | 47.12 | |
| | | | | | | | | | | | | |
December 31, 20202021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 110.3 | | | Discounted Cash Flow | | Forward Market Price | | $ | 16.19 | | | $ | 46.98 | | | $ | 28.30 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
Energy Contracts | $ | — | | | $ | 92.5 | | | Discounted Cash Flow | | Forward Market Price | | $ | 14.26 | | | $ | 52.98 | | | $ | 30.68 | |
| | | | | | | | | | | | | |
PSO
Significant Unobservable Inputs
September 30, 20212022
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
FTRs | $ | 18.7 | | | $ | 0.2 | | | Discounted Cash Flow | | Forward Market Price | | $ | (18.86) | | | $ | 4.10 | | | $ | (2.44) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
| | | | | | | | | | | | | |
FTRs | $ | 45.2 | | | $ | 0.8 | | | Discounted Cash Flow | | Forward Market Price | | $ | (36.83) | | | $ | 5.65 | | | $ | (7.55) | |
| | | | | | | | | | | | | |
December 31, 20202021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
FTRs | $ | 10.3 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price | | $ | (6.93) | | | $ | 0.48 | | | $ | (1.93) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Significant | | Input/Range |
| Fair Value | | Valuation | | Unobservable | | | | | | Weighted |
| Assets | | Liabilities | | Technique | | Input (a) | | Low | | High | | Average (c) |
| (in millions) | | | | | | | | | | |
FTRs | $ | 12.2 | | | $ | 0.1 | | | Discounted Cash Flow | | Forward Market Price | | $ | (18.39) | | | $ | 1.87 | | | $ | (2.57) | |
SWEPCo
Significant Unobservable Inputs
September 30, 20212022
| | | Significant | | Input/Range | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | Weighted | | Fair Value | | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) | | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Natural Gas Contracts | Natural Gas Contracts | $ | 9.0 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 3.58 | | | $ | 6.27 | | | $ | 4.44 | | Natural Gas Contracts | $ | 6.9 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 6.15 | | | $ | 7.37 | | | $ | 6.94 | |
FTRs | FTRs | 10.8 | | | 0.2 | | | Discounted Cash Flow | | Forward Market Price (a) | | (18.86) | | | 4.10 | | | (2.44) | | FTRs | 30.1 | | | 0.8 | | | Discounted Cash Flow | | Forward Market Price (a) | | (36.83) | | | 5.65 | | | (7.55) | |
Total | Total | $ | 19.8 | | | $ | 0.2 | | | Total | $ | 37.0 | | | $ | 0.8 | | |
December 31, 20202021
| | | Significant | | Input/Range | | Significant | | Input/Range |
| | Fair Value | | Valuation | | Unobservable | | | Weighted | | Fair Value | | Valuation | | Unobservable | | | Weighted |
| | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) | | Assets | | Liabilities | | Technique | | Input | | Low | | High | | Average (c) |
| | (in millions) | | | | | | | | | | | | (in millions) | | | | | | | | | | |
Natural Gas Contracts | Natural Gas Contracts | $ | — | | | $ | 1.7 | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 2.18 | | | $ | 2.77 | | | $ | 2.41 | | Natural Gas Contracts | $ | 3.6 | | | $ | — | | | Discounted Cash Flow | | Forward Market Price (b) | | $ | 3.11 | | | $ | 4.02 | | | $ | 3.47 | |
FTRs | FTRs | 3.3 | | | — | | | Discounted Cash Flow | | Forward Market Price (a) | | (6.93) | | | 0.48 | | | (1.93) | | FTRs | 7.4 | | | 0.1 | | | Discounted Cash Flow | | Forward Market Price (a) | | (18.39) | | | 1.87 | | | (2.57) | |
Total | Total | $ | 3.3 | | | $ | 1.7 | | | Total | $ | 11.0 | | | $ | 0.1 | | |
(a)Represents market prices in dollars per MWh.
(b)Represents market prices in dollars per MMBtu.
(c)The weighted average is the product of the forward market price of the underlying commodity and volume weighted by term.
(d)Represents percentage discount applied toAmount excludes Risk Management Assets of $14.4 million classified as Assets Held for Sale on the publically available share price.balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(e)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(f)Amount excludes Risk Management Liabilities of $0.1 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(g)Amount excludes Risk Management Assets of $6 million classified as Assets Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(h)Amount excludes Risk Management Liabilities of $0.5 million classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts FTRs and Other InvestmentsFTRs for the Registrants as of September 30, 20212022 and December 31, 2020:2021:
Uncertainty of Fair Value Measurements
| | | | | | | | | | | | | | | | | | | | |
Significant Unobservable Input | | Position | | Change in Input | | Impact on Fair Value Measurement |
Forward Market Price | | Buy | | Increase (Decrease) | | Higher (Lower) |
Forward Market Price | | Sell | | Increase (Decrease) | | Lower (Higher) |
Liquidity Adjustment | | Buy | | Increase (Decrease) | | Lower (Higher) |
11. INCOME TAXES
The disclosures in this note apply to all Registrants unless indicated otherwise.
Effective Tax Rates (ETR)
The Registrants’ interim ETR reflect the estimated annual ETR for 20212022 and 2020,2021, adjusted for tax expense associated with certain discrete items.
The Registrants include the amortization of Excess ADIT not subject to normalization requirements in the annual estimated ETR when regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers over multiple interim periods. Certain regulatory proceedings instruct the Registrants to provide the benefits of Tax Reform to customers in a single period (e.g. by applying the Excess ADIT not subject to normalization requirements against an existing regulatory asset balance) and in these circumstances, the Registrants recognize the tax benefit discretely in the period recorded. The annual amount of Excess ADIT approved by the Registrant’s regulatory commissions may not impact the ETR ratably during each interim period due to the variability of pretax book income between interim periods and the application of an annual estimated ETR.
The ETR for each of the Registrants are included in the following tables:
| | | Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2022 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
U.S. Federal Statutory Rate | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | Increase (decrease) due to: | | Increase (decrease) due to: | |
State Income Tax, net of Federal Benefit | State Income Tax, net of Federal Benefit | | 0.6 | % | | 0.3 | % | | 3.0 | % | | (0.3) | % | | 1.9 | % | | 1.2 | % | | 5.0 | % | | (6.9) | % | State Income Tax, net of Federal Benefit | | (0.8) | % | | 0.5 | % | | 2.6 | % | | (6.2) | % | | 2.7 | % | | 0.7 | % | | 3.0 | % | | (5.3) | % |
Tax Reform Excess ADIT Reversal | Tax Reform Excess ADIT Reversal | | (8.5) | % | | (6.3) | % | | 0.3 | % | | (14.2) | % | | (16.1) | % | | (8.9) | % | | (19.8) | % | | (4.2) | % | Tax Reform Excess ADIT Reversal | | (9.7) | % | | (2.0) | % | | 0.3 | % | | (8.6) | % | | (13.3) | % | | (6.2) | % | | (21.9) | % | | (4.6) | % |
Production and Investment Tax Credits | Production and Investment Tax Credits | | (4.7) | % | | (0.3) | % | | — | % | | (0.2) | % | | (2.0) | % | | — | % | | (8.9) | % | | (5.4) | % | Production and Investment Tax Credits | | (12.0) | % | | (0.4) | % | | — | % | | — | % | | — | % | | — | % | | (43.7) | % | | (24.1) | % |
Flow Through | Flow Through | | — | % | | 0.3 | % | | 0.3 | % | | 0.4 | % | | (2.8) | % | | 0.6 | % | | 0.7 | % | | (0.2) | % | Flow Through | | (0.3) | % | | 0.2 | % | | 0.3 | % | | (0.7) | % | | (1.5) | % | | 0.4 | % | | 0.4 | % | | (1.3) | % |
AFUDC Equity | AFUDC Equity | | (1.2) | % | | (1.0) | % | | (2.2) | % | | (1.8) | % | | (1.0) | % | | (0.3) | % | | (0.2) | % | | (0.5) | % | AFUDC Equity | | (1.4) | % | | (1.2) | % | | (1.9) | % | | (0.4) | % | | (0.6) | % | | (0.8) | % | | (0.4) | % | | (0.2) | % |
Parent Company Loss Benefit | | — | % | | (1.1) | % | | (2.3) | % | | (1.2) | % | | (3.6) | % | | — | % | | — | % | | 0.7 | % | |
| Discrete Tax Adjustments | Discrete Tax Adjustments | | 0.2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | 1.2 | % | Discrete Tax Adjustments | | (0.2) | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % |
Other | Other | | 0.7 | % | | (0.1) | % | | 0.1 | % | | 0.3 | % | | 0.8 | % | | — | % | | (0.1) | % | | (0.2) | % | Other | | 1.0 | % | | 0.2 | % | | 0.2 | % | | — | % | | (0.5) | % | | 0.2 | % | | 0.2 | % | | (0.2) | % |
Effective Income Tax Rate | Effective Income Tax Rate | | 8.1 | % | | 12.8 | % | | 20.2 | % | | 4.0 | % | | (1.8) | % | | 13.6 | % | | (2.3) | % | | 5.5 | % | Effective Income Tax Rate | | (2.4) | % | | 18.3 | % | | 22.5 | % | | 5.1 | % | | 7.8 | % | | 15.3 | % | | (41.4) | % | | (14.7) | % |
| | | Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2021 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
U.S. Federal Statutory Rate | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | Increase (decrease) due to: | | Increase (decrease) due to: | |
State Income Tax, net of Federal Benefit | State Income Tax, net of Federal Benefit | | 2.7 | % | | 2.0 | % | | 2.9 | % | | 3.1 | % | | 3.4 | % | | 0.8 | % | | 4.6 | % | | 2.4 | % | State Income Tax, net of Federal Benefit | | 0.6 | % | | 0.3 | % | | 3.0 | % | | (0.3) | % | | 1.9 | % | | 1.2 | % | | 5.0 | % | | (6.9) | % |
Tax Reform Excess ADIT Reversal | Tax Reform Excess ADIT Reversal | | (11.0) | % | | (14.6) | % | | 0.4 | % | | (22.0) | % | | (16.7) | % | | (6.7) | % | | (20.3) | % | | (7.3) | % | Tax Reform Excess ADIT Reversal | | (8.5) | % | | (6.3) | % | | 0.3 | % | | (14.2) | % | | (16.1) | % | | (8.9) | % | | (19.8) | % | | (4.2) | % |
Production and Investment Tax Credits | Production and Investment Tax Credits | | (4.6) | % | | (0.5) | % | | — | % | | — | % | | (1.6) | % | | — | % | | (1.1) | % | | (0.5) | % | Production and Investment Tax Credits | | (4.7) | % | | (0.3) | % | | — | % | | (0.2) | % | | (2.0) | % | | — | % | | (8.9) | % | | (5.4) | % |
Flow Through | Flow Through | | 0.5 | % | | 0.2 | % | | 0.5 | % | | 1.6 | % | | 0.2 | % | | 0.9 | % | | 0.2 | % | | (1.2) | % | Flow Through | | — | % | | 0.3 | % | | 0.3 | % | | 0.4 | % | | (2.8) | % | | 0.6 | % | | 0.7 | % | | (0.2) | % |
AFUDC Equity | AFUDC Equity | | (1.5) | % | | (3.5) | % | | (2.6) | % | | (1.1) | % | | (0.9) | % | | (0.9) | % | | (0.6) | % | | (0.3) | % | AFUDC Equity | | (1.2) | % | | (1.0) | % | | (2.2) | % | | (1.8) | % | | (1.0) | % | | (0.3) | % | | (0.2) | % | | (0.5) | % |
Parent Company Loss Benefit | Parent Company Loss Benefit | | — | % | | — | % | | (0.9) | % | | (3.1) | % | | (3.7) | % | | (0.3) | % | | (1.7) | % | | (2.0) | % | Parent Company Loss Benefit | | — | % | | (1.1) | % | | (2.3) | % | | (1.2) | % | | (3.6) | % | | — | % | | — | % | | 0.7 | % |
Discrete Tax Adjustments (a) | Discrete Tax Adjustments (a) | | (7.4) | % | | (3.6) | % | | (0.2) | % | | (6.6) | % | | 2.3 | % | | 8.4 | % | | (0.6) | % | | (0.6) | % | Discrete Tax Adjustments (a) | | 0.2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | 1.2 | % |
Other | Other | | 0.1 | % | | 0.3 | % | | 0.1 | % | | — | % | | — | % | | 0.3 | % | | 0.1 | % | | (0.6) | % | Other | | 0.7 | % | | (0.1) | % | | 0.1 | % | | 0.3 | % | | 0.8 | % | | — | % | | (0.1) | % | | (0.2) | % |
Effective Income Tax Rate | Effective Income Tax Rate | | (0.2) | % | | 1.3 | % | | 21.2 | % | | (7.1) | % | | 4.0 | % | | 23.5 | % | | 1.6 | % | | 10.9 | % | Effective Income Tax Rate | | 8.1 | % | | 12.8 | % | | 20.2 | % | | 4.0 | % | | (1.8) | % | | 13.6 | % | | (2.3) | % | | 5.5 | % |
| |
| | | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2022 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
U.S. Federal Statutory Rate | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | Increase (decrease) due to: | | Increase (decrease) due to: | |
State Income Tax, net of Federal Benefit | State Income Tax, net of Federal Benefit | | 1.2 | % | | 0.3 | % | | 2.8 | % | | 1.5 | % | | 1.6 | % | | 0.8 | % | | 4.8 | % | | (3.4) | % | State Income Tax, net of Federal Benefit | | 0.7 | % | | 0.5 | % | | 2.7 | % | | (0.8) | % | | 1.3 | % | | 0.8 | % | | 3.2 | % | | (1.5) | % |
Tax Reform Excess ADIT Reversal | Tax Reform Excess ADIT Reversal | | (8.9) | % | | (7.2) | % | | 0.3 | % | | (15.2) | % | | (17.7) | % | | (9.1) | % | | (19.8) | % | | (4.3) | % | Tax Reform Excess ADIT Reversal | | (7.8) | % | | (2.0) | % | | 0.3 | % | | (10.3) | % | | (15.7) | % | | (7.3) | % | | (20.8) | % | | (4.8) | % |
Production and Investment Tax Credits | Production and Investment Tax Credits | | (4.9) | % | | (0.3) | % | | — | % | | — | % | | (2.2) | % | | — | % | | (8.1) | % | | (4.6) | % | Production and Investment Tax Credits | | (8.7) | % | | (0.4) | % | | — | % | | — | % | | (1.4) | % | | — | % | | (39.5) | % | | (22.5) | % |
Flow Through | Flow Through | | 0.2 | % | | 0.3 | % | | 0.3 | % | | 1.7 | % | | (3.0) | % | | 0.9 | % | | 0.7 | % | | (0.2) | % | Flow Through | | — | % | | 0.2 | % | | 0.3 | % | | 0.2 | % | | (1.6) | % | | 0.5 | % | | 0.3 | % | | (0.8) | % |
AFUDC Equity | AFUDC Equity | | (1.1) | % | | (1.1) | % | | (1.9) | % | | (1.2) | % | | (1.0) | % | | (0.8) | % | | (0.3) | % | | (0.6) | % | AFUDC Equity | | (1.1) | % | | (1.2) | % | | (1.9) | % | | (0.8) | % | | (0.8) | % | | (0.7) | % | | (0.4) | % | | (0.4) | % |
Parent Company Loss Benefit | | — | % | | (0.7) | % | | (1.9) | % | | (1.3) | % | | (2.8) | % | | — | % | | — | % | | — | % | |
| Discrete Tax Adjustments | Discrete Tax Adjustments | | 1.1 | % | | — | % | | — | % | | — | % | | — | % | | (1.3) | % | | (0.9) | % | | 0.6 | % | Discrete Tax Adjustments | | (0.2) | % | | — | % | | — | % | | (1.8) | % | | — | % | | — | % | | — | % | | 0.3 | % |
Other | Other | | 0.1 | % | | — | % | | — | % | | 0.1 | % | | 0.4 | % | | 0.2 | % | | (0.2) | % | | (0.1) | % | Other | | 0.6 | % | | 0.1 | % | | 0.1 | % | | — | % | | 0.2 | % | | 0.1 | % | | 0.2 | % | | — | % |
Effective Income Tax Rate | Effective Income Tax Rate | | 8.7 | % | | 12.3 | % | | 20.6 | % | | 6.6 | % | | (3.7) | % | | 11.7 | % | | (2.8) | % | | 8.4 | % | Effective Income Tax Rate | | 4.5 | % | | 18.2 | % | | 22.5 | % | | 7.5 | % | | 3.0 | % | | 14.4 | % | | (36.0) | % | | (8.7) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2020 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | | | | | | | | | | | | | | | | |
State Income Tax, net of Federal Benefit | | 2.6 | % | | 1.8 | % | | 2.9 | % | | 3.1 | % | | 3.4 | % | | 0.7 | % | | 4.6 | % | | 2.3 | % |
Tax Reform Excess ADIT Reversal | | (12.1) | % | | (23.4) | % | | 0.4 | % | | (20.8) | % | | (16.7) | % | | (8.8) | % | | (20.3) | % | | (11.5) | % |
Production and Investment Tax Credits | | (4.5) | % | | (0.5) | % | | — | % | | — | % | | (1.6) | % | | — | % | | (1.1) | % | | (0.5) | % |
Flow Through | | 0.5 | % | | 0.1 | % | | 0.5 | % | | 1.6 | % | | 0.2 | % | | 0.9 | % | | 0.2 | % | | (1.2) | % |
AFUDC Equity | | (1.5) | % | | (3.2) | % | | (2.6) | % | | (1.1) | % | | (0.9) | % | | (0.9) | % | | (0.6) | % | | (0.3) | % |
Parent Company Loss Benefit | | — | % | | — | % | | (0.9) | % | | (3.1) | % | | (3.7) | % | | (0.3) | % | | (1.7) | % | | (1.9) | % |
Discrete Tax Adjustments (a) | | (3.0) | % | | (1.6) | % | | (0.1) | % | | (2.3) | % | | 1.8 | % | | 2.6 | % | | (0.4) | % | | (0.3) | % |
Other | | 0.2 | % | | 0.4 | % | | (0.1) | % | | (0.1) | % | | (0.1) | % | | 0.2 | % | | 0.1 | % | | (0.4) | % |
Effective Income Tax Rate | | 3.2 | % | | (5.4) | % | | 21.1 | % | | (1.7) | % | | 3.4 | % | | 15.4 | % | | 1.8 | % | | 7.2 | % |
(a)The discrete tax expense is primarily attributable to the $48 million benefit recognized as a result of the 5-year net operating losses (NOL) carryback provision of the CARES Act. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2021 |
| | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
U.S. Federal Statutory Rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | | | | | | | | | | | | | | | | |
State Income Tax, net of Federal Benefit | | 1.2 | % | | 0.3 | % | | 2.8 | % | | 1.5 | % | | 1.6 | % | | 0.8 | % | | 4.8 | % | | (3.4) | % |
Tax Reform Excess ADIT Reversal | | (8.9) | % | | (7.2) | % | | 0.3 | % | | (15.2) | % | | (17.7) | % | | (9.1) | % | | (19.8) | % | | (4.3) | % |
Production and Investment Tax Credits | | (4.9) | % | | (0.3) | % | | — | % | | — | % | | (2.2) | % | | — | % | | (8.1) | % | | (4.6) | % |
Flow Through | | 0.2 | % | | 0.3 | % | | 0.3 | % | | 1.7 | % | | (3.0) | % | | 0.9 | % | | 0.7 | % | | (0.2) | % |
AFUDC Equity | | (1.1) | % | | (1.1) | % | | (1.9) | % | | (1.2) | % | | (1.0) | % | | (0.8) | % | | (0.3) | % | | (0.6) | % |
Parent Company Loss Benefit | | — | % | | (0.7) | % | | (1.9) | % | | (1.3) | % | | (2.8) | % | | — | % | | — | % | | — | % |
Discrete Tax Adjustments | | 1.1 | % | | — | % | | — | % | | — | % | | — | % | | (1.3) | % | | (0.9) | % | | 0.6 | % |
Other | | 0.1 | % | | — | % | | — | % | | 0.1 | % | | 0.4 | % | | 0.2 | % | | (0.2) | % | | (0.1) | % |
Effective Income Tax Rate | | 8.7 | % | | 12.3 | % | | 20.6 | % | | 6.6 | % | | (3.7) | % | | 11.7 | % | | (2.8) | % | | 8.4 | % |
Federal and State Income Tax Audit Status
The statute of limitations for the IRS to examine AEP and subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, AEP and subsidiaries elected to amend the 2014 through 2017 federal returns. In the first quarter of 2020, the IRS notified AEP that it was beginning an examination of these amended returns, including the NOLnet operating loss carryback to 2015 that originated in the 2017 return. As of September 30, 2021,2022, the IRS has not challenged any items on theseaccepted the 2014-2016 amended tax returns andas filed which completes the IRS is limited in theiraudit of these tax years. Additionally, AEP has received and agreed to two proposed adjustments to the amount AEP claimed on the amended returns.2017 tax return, which were immaterial. AEP has agreed to extend the statute of limitations on the 2017 and 2018 tax return to December 31, 20222023 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.
AEP and subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and AEP and subsidiaries are currently under examination in several state and local jurisdictions. The Registrants are no longer subjectGenerally, the statutes of limitations have expired for tax years prior to state or local examinations by tax authorities for years before 2012.2017. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.
Federal Legislation
In March 2020,On August 16, 2022, President Biden signed H.R. 5376 into law, commonly known as the CARESInflation Reduction Act was signed into law. The CARES Act includesof 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax relief provisions includingon adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a 5-year NOL carryback from years 2018-2020. Innuclear and clean hydrogen PTC, an energy storage ITC and allows the sale or transfer of tax credits to third quarterparties for cash. With the exception of 2020, AEP requested a $95 million refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. AEP carried back a NOL generatedPTCs and ITCs, this legislation is prospective and has no material impact on the 2019 Federal incomecurrent period financial statements. As significant guidance from Treasury and the IRS is expected on the tax return at a 21% federal corporate income tax rate to the 2014 Federal income tax return at a 35% corporate income tax rate. As a result of the changeprovisions in the corporateIRA, AEP will continue to monitor any issued guidance and evaluate the impact on future net income, tax rates between the two periods, AEP realized a tax benefit of $48 million primarily at the Generation & Marketing segment in 2020.
State Legislation
In April 2021, West Virginia enacted House Bill (H.B.) 2026. H.B. 2026 changes the state income tax apportionment formula from a ratio that includes property, payrollcash flows and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. H.B. 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property. In the second quarter of 2021, AEP recorded $20 million in Income Tax Expense as a result of remeasuring West Virginia deferred taxes under the new apportionment methodology. The enacted legislation does not impact AEP Texas, PSO or SWEPCo.
In May 2021, Oklahoma enacted House Bill (H.B.) 2960. H.B. 2960 reduces the Oklahoma corporate income tax rate from 6% to 4%. In the second quarter of 2021, AEP recorded a $1 million Income Tax Benefit as a result of remeasuring Oklahoma deferred taxes at the lowered statutory tax rate of 4%. The enacted legislation does not impact APCo, I&M or OPCo.financial condition.
12. FINANCING ACTIVITIES
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Common Stock (Applies to AEP)
At-the-Market (ATM) Program
In 2020, AEP filed a prospectus supplement and executed an Equity Distribution Agreement, pursuant to which AEP may sell, from time to time, up to an aggregate of $1 billion of its common stock through an ATM offering program, including an equity forward sales component. The compensation paid to the selling agents by AEP may be up to 2% of the gross offering proceeds of the shares. ForThere were no issuances under the ATM program for the nine months ended September 30, 2021, AEP issued 5,421,825 shares of common stock and received net cash proceeds of $461 million under the ATM program.2022.
Long-term Debt Outstanding (Applies to AEP)
The following table details long-term debt outstanding, net of issuance costs and premiums or discounts:
| Type of Debt | Type of Debt | | September 30, 2021 | | December 31, 2020 | Type of Debt | | September 30, 2022 | | December 31, 2021 |
| | | (in millions) | | | (in millions) |
Senior Unsecured Notes | Senior Unsecured Notes | | $ | 28,778.1 | | | $ | 25,116.1 | | Senior Unsecured Notes | | $ | 28,892.7 | | | $ | 27,497.3 | |
Pollution Control Bonds | Pollution Control Bonds | | 1,881.0 | | | 1,936.7 | | Pollution Control Bonds | | 1,804.9 | | | 1,804.5 | |
Notes Payable | Notes Payable | | 235.1 | | | 239.1 | | Notes Payable | | 218.0 | | | 211.3 | |
Securitization Bonds | Securitization Bonds | | 639.7 | | | 716.4 | | Securitization Bonds | | 524.8 | | | 603.5 | |
Spent Nuclear Fuel Obligation (a) | Spent Nuclear Fuel Obligation (a) | | 281.3 | | | 281.2 | | Spent Nuclear Fuel Obligation (a) | | 283.2 | | | 281.3 | |
Junior Subordinated Notes (b) | Junior Subordinated Notes (b) | | 1,629.9 | | | 1,624.1 | | Junior Subordinated Notes (b) | | 2,377.3 | | | 2,373.0 | |
Other Long-term Debt | Other Long-term Debt | | 1,133.2 | | | 1,158.9 | | Other Long-term Debt | | 949.2 | | | 683.6 | |
Total Long-term Debt Outstanding | Total Long-term Debt Outstanding | | 34,578.3 | | | 31,072.5 | | Total Long-term Debt Outstanding | | 35,050.1 | | | 33,454.5 | |
Long-term Debt Due Within One Year(c) | Long-term Debt Due Within One Year(c) | | 2,521.8 | | | 2,086.1 | | Long-term Debt Due Within One Year(c) | | 1,403.5 | | | 2,153.8 | |
Long-term Debt(d) | Long-term Debt(d) | | $ | 32,056.5 | | | $ | 28,986.4 | | Long-term Debt(d) | | $ | 33,646.6 | | | $ | 31,300.7 | |
(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for SNF disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $327$326 million and $324$329 million as of September 30, 20212022 and December 31, 2020,2021, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
(b)See “Equity Units” section below for additional information.
(c)Amount excludes $215 million and $200 million as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt Due Within One Year classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
(d)Amount excludes $963 million and $903 million as of September 30, 2022 and December 31, 2021, respectively, of Long-term Debt classified as Liabilities Held for Sale on the balance sheet. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
Long-term Debt Activity
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 20212022 are shown in the following tables:
| | | Principal | | Interest | | | Principal | | Interest | |
Company | Company | | Type of Debt | | Amount (a) | | Rate | | Due Date | Company | | Type of Debt | | Amount (a) | | Rate | | Due Date |
Issuances: | Issuances: | | | | (in millions) | | (%) | | | Issuances: | | | | (in millions) | | (%) | | |
| AEP | | Senior Unsecured Notes | | $ | 175.0 | | | 1.80 | | 2028 | |
| AEP Texas | | AEP Texas | | Other Long-term Debt | | $ | 200.0 | | | Variable | | 2025 |
AEP Texas | | AEP Texas | | Senior Unsecured Notes | | 500.0 | | | 4.70 | | 2032 |
AEP Texas | AEP Texas | | Senior Unsecured Notes | | 450.0 | | | 3.45 | | 2051 | AEP Texas | | Senior Unsecured Notes | | 500.0 | | | 5.25 | | 2052 |
AEPTCo | AEPTCo | | Senior Unsecured Notes | | 450.0 | | | 2.75 | | 2051 | AEPTCo | | Senior Unsecured Notes | | 550.0 | | | 4.50 | | 2052 |
| APCo | APCo | | Senior Unsecured Notes | | 500.0 | | | 2.70 | | 2031 | APCo | | Other Long-term Debt | | 100.0 | | | Variable | | 2023 |
APCo | | APCo | | Pollution Control Bonds | | 104.4 | | | 3.75 | | 2025 |
APCo | | APCo | | Senior Unsecured Notes | | 500.0 | | | 4.50 | | 2032 |
| I&M | I&M | | Notes Payable | | 64.9 | | | 0.93 | | 2025 | I&M | | Notes Payable | | 72.8 | | | 3.44 | | 2026 |
I&M | | Senior Unsecured Notes | | 450.0 | | | 3.25 | | 2051 | |
OPCo | | Senior Unsecured Notes | | 450.0 | | | 1.63 | | 2031 | |
OPCo | | Senior Unsecured Notes | | 600.0 | | | 2.90 | | 2051 | |
PSO | PSO | | Other Long-term Debt | | 500.0 | | | Variable | | 2022 | PSO | | Other Long-term Debt | | 500.0 | | | Variable | | 2022 |
PSO | | Senior Unsecured Notes | | 400.0 | | | 2.20 | | 2031 | |
PSO | | Senior Unsecured Notes | | 400.0 | | | 3.15 | | 2051 | |
SWEPCo | | Senior Unsecured Notes | | 500.0 | | | 1.65 | | 2026 | |
| Non-Registrant: | Non-Registrant: | | Non-Registrant: | |
AEGCo | | AEGCo | | Pollution Control Bonds | | 45.0 | | | 3.13 | | 2025 |
| KPCo | KPCo | | Other Long-term Debt | | 150.0 | | | Variable | | 2023 | KPCo | | Other Long-term Debt | | 150.0 | | | Variable | | 2023 |
Transource Energy | Transource Energy | | Other Long-term Debt | | 25.9 | | | Variable | | 2023 | Transource Energy | | Other Long-term Debt | | 5.0 | | | Variable | | 2023 |
WPCo | | WPCo | | Other Long-term Debt | | 165.0 | | | Variable | | 2024 |
WPCo | | WPCo | | Pollution Control Bonds | | 65.0 | | | 3.00 | | 2027 |
| Total Issuances | Total Issuances | | $ | 5,115.8 | | | Total Issuances | | $ | 3,457.2 | | |
(a)Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
AEP Texas | | Securitization Bonds | | $ | 29.7 | | | 2.85 | | 2024 |
AEP Texas | | Securitization Bonds | | 22.5 | | | 2.06 | | 2025 |
| | | | | | | | |
APCo | | Senior Unsecured Notes | | 350.0 | | | 4.60 | | 2021 |
APCo | | Pollution Control Bonds | | 17.5 | | | 4.63 | | 2021 |
APCo | | Securitization Bonds | | 25.4 | | | 2.01 | | 2023 |
APCo | | Other Long-term Debt | | 0.1 | | | 13.72 | | 2026 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
I&M | | Other Long-term Debt | | 200.0 | | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | 40.0 | | | 2.05 | | 2021 |
I&M | | Notes Payable | | 1.9 | | | Variable | | 2021 |
I&M | | Notes Payable | | 4.5 | | | Variable | | 2022 |
I&M | | Notes Payable | | 5.4 | | | Variable | | 2022 |
I&M | | Notes Payable | | 14.3 | | | Variable | | 2023 |
I&M | | Notes Payable | | 12.6 | | | Variable | | 2024 |
| | | | | | | | |
I&M | | Notes Payable | | 19.6 | | | Variable | | 2025 |
I&M | | Notes Payable | | 7.4 | | | 0.93 | | 2025 |
I&M | | Other Long-term Debt | | 1.5 | | | 6.00 | | 2025 |
| | | | | | | | |
| | | | | | | | |
OPCo | | Other Long-term Debt | | 0.1 | | | 1.15 | | 2028 |
PSO | | Senior Unsecured Notes | | 250.0 | | | 4.40 | | 2021 |
PSO | | Other Long-term Debt | | 500.0 | | | Variable | | 2022 |
PSO | | Other Long-term Debt | | 0.4 | | | 3.00 | | 2027 |
SWEPCo | | Other Long-term Debt | | 1.5 | | | 4.68 | | 2028 |
SWEPCo | | Notes Payable | | 3.2 | | | 4.58 | | 2032 |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
KPCo | | Senior Unsecured Notes | | 39.8 | | | 7.25 | | 2021 |
Transource Energy | | Senior Unsecured Notes | | 1.2 | | | 2.75 | | 2050 |
Transource Energy | | Senior Unsecured Notes | | 1.2 | | | 2.75 | | 2050 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total Retirements and Principal Payments | | | | $ | 1,549.8 | | | | | |
As of September 30, 2021, trustees held, on behalf of I&M, $40 million of its reacquired Pollution Control Bonds. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Principal | | Interest | | |
Company | | Type of Debt | | Amount Paid | | Rate | | Due Date |
Retirements and Principal Payments: | | | | (in millions) | | (%) | | |
| | | | | | | | |
AEP Texas | | Other Long-term Debt | | $ | 200.0 | | | Variable | | 2022 |
AEP Texas | | Senior Unsecured Notes | | 400.0 | | | 2.40 | | 2022 |
AEP Texas | | Senior Unsecured Notes | | 25.0 | | | 3.27 | | 2022 |
AEP Texas | | Securitization Bonds | | 30.6 | | | 2.85 | | 2024 |
AEP Texas | | Securitization Bonds | | 23.0 | | | 2.06 | | 2025 |
| | | | | | | | |
| | | | | | | | |
APCo | | Pollution Control Bonds | | 104.4 | | | 2.63 | | 2022 |
APCo | | Securitization Bonds | | 25.9 | | | 2.01 | | 2023 |
APCo | | Other Long-term Debt | | 0.1 | | | 13.72 | | 2026 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
I&M | | Notes Payable | | 3.4 | | | Variable | | 2022 |
I&M | | Notes Payable | | 1.3 | | | Variable | | 2022 |
I&M | | Notes Payable | | 6.7 | | | Variable | | 2023 |
I&M | | Notes Payable | | 10.8 | | | Variable | | 2024 |
I&M | | Notes Payable | | 18.9 | | | 0.93 | | 2025 |
I&M | | Notes Payable | | 13.7 | | | Variable | | 2025 |
I&M | | Notes Payable | | 8.0 | | | 3.44 | | 2026 |
I&M | | Other Long-term Debt | | 1.7 | | | 6.00 | | 2025 |
| | | | | | | | |
OPCo | | Other Long-term Debt | | 0.1 | | | 1.15 | | 2028 |
| | | | | | | | |
PSO | | Other Long-term Debt | | 500.0 | | | Variable | | 2022 |
PSO | | Other Long-term Debt | | 0.4 | | | 3.00 | | 2027 |
SWEPCo | | Other Long-term Debt | | 1.5 | | | 4.68 | | 2028 |
SWEPCo | | Notes Payable | | 3.2 | | | 4.58 | | 2032 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Non-Registrant: | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
AEGCo | | Pollution Control Bonds | | 45.0 | | | 1.35 | | 2022 |
KPCo | | Other Long-term Debt | | 75.0 | | | Variable | | 2022 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Transource Energy | | Senior Unsecured Notes | | 2.4 | | | 2.75 | | 2050 |
| | | | | | | | |
WPCo | | Pollution Control Bonds | | 65.0 | | | 3.00 | | 2022 |
WPCo | | Senior Unsecured Notes | | 113.0 | | | 3.36 | | 2022 |
Total Retirements and Principal Payments | | | | $ | 1,679.1 | | | | | |
Long-term Debt Subsequent Event
In October 2021,2022, AEGCo retired $120 million of Other Long-term Debt.
In October 2022, AEGCo issued $80 million of variable rate Other Long-term Debt due in 2024.
In October 2022, AEPTCo retired $104 million of Senior Unsecured Notes.
In October 2022, APCo retired $100 million of Pollution Control Bonds.
In October 2022, I&M retired $8$7 million of Notes Payable related to DCC Fuel.
In October 2021, OPCo retired $5002022, Transource Energy issued $64 million of Senior Unsecured Notes.variable rate Other Long-term Debt due in 2025.
In October 2022, Transource Energy retired $64 million of Other Long-term Debt.
Equity Units (Applies to AEP)
2020 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. The proceeds were used to support AEP’s overall capital expenditure plans.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 1.30% Junior Subordinated Notes (notes) due in 2025 and a forward equity purchase contract which settles after three years in 2023. The notes are expected to be remarketed in 2023, at which time the interest rate will reset at the then current market rate. Investors may choose to remarket their notes to receive the remarketing proceeds and use those funds to settle the forward equity purchase contract, or accept the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the right to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 1.30% and a quarterly forward equity purchase contract payment of 4.825%.
Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance with the conversion ratios set forth below (subject to an anti-dilution adjustment):
•If the AEP common stock market price is equal to or greater than $99.95: 0.5003 shares per contract.
•If the AEP common stock market price is less than $99.95 but greater than $83.29: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $83.29: 0.6003 shares per contract.
A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
At the time of issuance, the $850 million of notes were recorded within Long-term Debt on the balance sheets. The present value of the purchase contract payments of $121 million were recorded in Deferred Credits and Other Noncurrent Liabilities with a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2023. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. The maximum amount of shares AEP will be required to issue to settle the purchase contract is 10,205,100 shares (subject to an anti-dilution adjustment).
2019 Equity Units
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. The proceeds were used to support AEP’s overall capital expenditure plans including the acquisition of Sempra Renewables LLC.
Each corporate unit represents a 1/20 undivided beneficial ownership interest in $1,000 principal amount of AEP’s 3.40% Junior Subordinated Notes (notes) due in 2024 and a forward equity purchase contract which settlessettled after three years in 2022. TheIn January 2022, AEP successfully remarketed the notes are expected to be remarketed in 2022, at which timeon behalf of holders of the interest rate will reset atcorporate units and did not directly receive any proceeds therefrom. Instead, the then current market rate. Investors may choose to remarket their notes to receiveholders of the corporate units used the debt remarketing proceeds and use those funds to settle the forward equity purchase contract or acceptwith AEP. The interest rate on the remarketed debt and use other funds for the equity purchase. If the remarketing is unsuccessful, investors have the rightnotes was reset to put their notes to AEP at a price equal to the principal. The Equity Units carry an annual distribution rate of 6.125%, which is comprised of a quarterly coupon rate of interest of 3.40% and a quarterly forward equity purchase contract payment of 2.725%.
Each forward equity purchase contract obligates the holder to purchase, and AEP to sell, for $50 a number of shares in common stock in accordance2.031% with the conversion ratios set forth below (subject to an anti-dilution adjustment):
•If thematurity remaining in 2024. In March 2022, AEP common stock market price is equal to or greater than $99.58: 0.5021issued 8,970,920 shares per contract.
•If theof AEP common stock market price is less than $99.58 but greater than $82.98: a number of shares per contract equal to $50 divided by the applicable market price. The holder receives a variable number of shares at $50.
•If the AEP common stock market price is less than or equal to $82.98: 0.6026 shares per contract.
A holder’s ownership interest in the notes is pledged to AEP to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the forward equity purchase contract must be secured by a U.S. Treasury security which must be equal to the aggregate principal amount of the notes.
At the time of issuance, thecommon stock and received proceeds totaling $805 million of notes were recorded within Long-term Debt onunder the balance sheets. The present value of the purchase contract payments of $62 million were recorded in Deferred Credits and Other Noncurrent Liabilitieswith a current portion in Other Current Liabilities at the time of issuance, representing the obligation to make forward equity contract payments, with an offsetting reduction to Paid-in Capital. The difference between the face value and present value of the purchase contract payments will be accreted to Interest Expense on the statements of income over the three year period ending in 2022. The liability recorded for the contract payments is considered non-cash and excluded from the statements of cash flows. Until settlement of the forward equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under thecontract. AEP common stock held in treasury stock method. The maximum amount of shares AEP will be required to issuewas used to settle the forward equity purchase contract is 9,701,860 shares (subject to an anti-dilution adjustment).contract.
Debt Covenants (Applies to AEP and AEPTCo)
Covenants in AEPTCo’s note purchase agreements and indenture limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. AEPTCo’s contractually-defined priority debt was 0.1%0.5% of consolidated tangible net assets as of September 30, 2021.2022. The method for calculating the consolidated tangible net assets is contractually-defined in the note purchase agreements.
Dividend Restrictions
Utility Subsidiaries’ Restrictions
Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. 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.
All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restrictionrequirement that prohibits the payment of dividends out of capital accounts without regulatory approval;in certain circumstances; payment of dividends is generally allowed out of retained earnings only.earnings. The Federal Power Act also creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M.
Certain AEP subsidiaries have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.
The Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings.
Parent Restrictions (Applies to AEP)
The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries.
Pursuant to the leverage restrictions in credit agreements, AEP must 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 the credit agreements.
Corporate Borrowing Program - AEP System (Applies to all Registrant Subsidiaries)
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries; a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries; and direct borrowing from AEP. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 20212022 and December 31, 20202021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ activity and corresponding authorized borrowing limits for the nine months ended September 30, 20212022 are described in the following table:
| | | Maximum | | Average | | Net Loans to | | | Maximum | | Average | | Net Loans to | |
| | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings) from | | Authorized | | | Borrowings | | Maximum | | Borrowings | | Average | | (Borrowings) from | | Authorized | |
| | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term | | | from the | | Loans to the | | from the | | Loans to the | | the Utility Money | | Short-term | |
| | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing | | | Utility | | Utility | | Utility | | Utility | | Pool as of | | Borrowing | |
Company | Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2021 | | Limit | | Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2022 | | Limit | |
| | | (in millions) | | | (in millions) |
AEP Texas | AEP Texas | | $ | 355.5 | | | $ | 104.7 | | | $ | 234.7 | | | $ | 45.2 | | | $ | 47.6 | | | $ | 500.0 | | | AEP Texas | | $ | 348.8 | | | $ | 652.3 | | | $ | 208.1 | | | $ | 319.8 | | | $ | 129.5 | | | $ | 500.0 | | |
AEPTCo | AEPTCo | | 444.9 | | | 117.3 | | | 225.1 | | | 24.4 | | | 73.9 | | | 820.0 | | (a) | AEPTCo | | 480.2 | | | 137.0 | | | 197.4 | | | 31.3 | | | 78.7 | | (a) | 820.0 | | (b) |
APCo | APCo | | 27.8 | | | 616.9 | | | 13.2 | | | 134.4 | | | 185.2 | | | 500.0 | | | APCo | | 438.4 | | | 214.2 | | | 180.9 | | | 52.8 | | | 182.1 | | | 500.0 | | |
I&M | I&M | | 166.5 | | | 368.2 | | | 117.5 | | | 76.3 | | | 80.6 | | | 500.0 | | | I&M | | 159.1 | | | 22.6 | | | 86.0 | | | 22.1 | | | (82.3) | | | 500.0 | | |
OPCo | OPCo | | 259.2 | | | 622.9 | | | 62.8 | | | 182.5 | | | 622.9 | | | 500.0 | | | OPCo | | 147.2 | | | 246.1 | | | 59.9 | | | 86.9 | | | (68.8) | | | 500.0 | | |
PSO | PSO | | 267.7 | | | 747.3 | | | 142.8 | | | 184.9 | | | 59.5 | | | 300.0 | | | PSO | | 338.3 | | | 432.5 | | | 200.9 | | | 402.8 | | | (223.5) | | | 400.0 | | |
SWEPCo | SWEPCo | | 280.3 | | | 156.4 | | | 148.0 | | | 142.0 | | | (122.9) | | | 350.0 | | | SWEPCo | | 261.6 | | | 156.6 | | | 191.0 | | | 109.7 | | | (156.3) | | | 400.0 | | |
(a) Amount excludes $5 million of Advances to Affiliates classified as Assets Held for Sale on the AEPTCo balance sheet. See “Dispositions of KPCo and KTCo” section of Note 6 for additional information.
(b) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
The activity in the above table does not include short-term lending activity of certain AEP nonutility subsidiaries. AEP Texas’ wholly-owned subsidiary, AEP Texas North Generation Company, LLC and SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC participate in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 20212022 and December 31, 20202021 are included in Advances to Affiliates on the subsidiaries’ balance sheets. The Nonutility Money Pool participants’ activity for the nine months ended September 30, 20212022 is described in the following table:
| | | Maximum Loans | | Average Loans | | Loans to the Nonutility | | Maximum Loans | | Average Loans | | Loans to the Nonutility |
| | to the Nonutility | | to the Nonutility | | Money Pool as of | | to the Nonutility | | to the Nonutility | | Money Pool as of |
Company | Company | | Money Pool | | Money Pool | | September 30, 2021 | Company | | Money Pool | | Money Pool | | September 30, 2022 |
| | (in millions) | | (in millions) |
AEP Texas | AEP Texas | | $ | 7.1 | | | $ | 6.9 | | | $ | 7.0 | | AEP Texas | | $ | 6.9 | | | $ | 6.8 | | | $ | 6.8 | |
SWEPCo | SWEPCo | | 2.1 | | | 2.1 | | | 2.1 | | SWEPCo | | 2.1 | | | 2.1 | | | 2.1 | |
AEP has a direct financing relationship with AEPTCo to meet its short-term borrowing needs. The amounts of outstanding loans to and borrowings from AEP as of September 30, 20212022 and December 31, 20202021 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP and corresponding authorized borrowing limit for the nine months ended September 30, 20212022 are described in the following table:
| Maximum | Maximum | | Maximum | | Average | | Average | | Borrowings from | | Loans to | | Authorized | | Maximum | | Maximum | | Average | | Average | | Borrowings from | | Loans to | | Authorized | |
Borrowings | Borrowings | | Loans | | Borrowings | | Loans | | AEP as of | | AEP as of | | Short-term | | Borrowings | | Loans | | Borrowings | | Loans | | AEP as of | | AEP as of | | Short-term | |
from AEP | from AEP | | to AEP | | from AEP | | to AEP | | September 30, 2021 | | September 30, 2021 | | Borrowing Limit | | from AEP | | to AEP | | from AEP | | to AEP | | September 30, 2022 | | September 30, 2022 | | Borrowing Limit | |
(in millions) | (in millions) | (in millions) |
$ | 14.6 | | | $ | 224.2 | | | $ | 1.6 | | | $ | 139.3 | | | $ | 8.6 | | | $ | — | | | $ | 50.0 | | (a) | 52.4 | | | $ | 141.8 | | | $ | 7.1 | | | $ | 59.6 | | | $ | 33.0 | | | $ | — | | | $ | 50.0 | | (a) |
(a) Amount represents the combined authorized short-term borrowing limit the State Transcos have from FERC or state regulatory commissions.
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
| | | | Nine Months Ended September 30, | | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2022 | | 2021 |
Maximum Interest Rate | Maximum Interest Rate | | 0.40 | % | | 2.70 | % | Maximum Interest Rate | | 3.39 | % | | 0.40 | % |
Minimum Interest Rate | Minimum Interest Rate | | 0.02 | % | | 0.33 | % | Minimum Interest Rate | | 0.10 | % | | 0.02 | % |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table:
| | | Average Interest Rate for Funds | | Average Interest Rate for Funds | | Average Interest Rate for Funds | | Average Interest Rate for Funds |
| | Borrowed from the Utility Money Pool | | Loaned to the Utility Money Pool | | Borrowed from the Utility Money Pool | | Loaned to the Utility Money Pool |
| | for Nine Months Ended September 30, | | for Nine Months Ended September 30, | | for Nine Months Ended September 30, | | for Nine Months Ended September 30, |
Company | Company | | 2021 | | 2020 | | 2021 | | 2020 | Company | | 2022 | | 2021 | | 2022 | | 2021 |
AEP Texas | AEP Texas | | 0.33 | % | | 1.55 | % | | 0.27 | % | | 0.87 | % | AEP Texas | | 0.90 | % | | 0.33 | % | | 1.82 | % | | 0.27 | % |
AEPTCo | AEPTCo | | 0.32 | % | | 1.63 | % | | 0.07 | % | | 2.00 | % | AEPTCo | | 1.03 | % | | 0.32 | % | | 2.14 | % | | 0.07 | % |
APCo | APCo | | 0.28 | % | | 2.14 | % | | 0.28 | % | | 0.99 | % | APCo | | 1.39 | % | | 0.28 | % | | 2.13 | % | | 0.28 | % |
I&M | I&M | | 0.32 | % | | 1.30 | % | | 0.25 | % | | 1.44 | % | I&M | | 1.38 | % | | 0.32 | % | | 1.46 | % | | 0.25 | % |
OPCo | OPCo | | 0.27 | % | | 1.32 | % | | 0.15 | % | | 2.06 | % | OPCo | | 1.81 | % | | 0.27 | % | | 1.22 | % | | 0.15 | % |
PSO | PSO | | 0.34 | % | | 1.24 | % | | 0.06 | % | | 1.95 | % | PSO | | 1.70 | % | | 0.34 | % | | 0.75 | % | | 0.06 | % |
SWEPCo | SWEPCo | | 0.28 | % | | 1.55 | % | | 0.38 | % | | — | % | SWEPCo | | 1.67 | % | | 0.28 | % | | 0.55 | % | | 0.38 | % |
Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized in the following table:
| | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2022 | | Nine Months Ended September 30, 2021 |
| | | Maximum | | Minimum | | Average | | Maximum | | Minimum | | Average | | | Maximum | | Minimum | | Average | | Maximum | | Minimum | | Average |
| | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
| | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
| | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to | | Loaned to |
| | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility | | the Nonutility |
Company | Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | Money Pool |
AEP Texas | AEP Texas | | 0.41 | % | | 0.21 | % | | 0.34 | % | | 2.70 | % | | 0.33 | % | | 1.44 | % | AEP Texas | | 3.39 | % | | 0.46 | % | | 1.51 | % | | 0.41 | % | | 0.21 | % | | 0.34 | % |
SWEPCo | SWEPCo | | 0.41 | % | | 0.21 | % | | 0.34 | % | | 2.70 | % | | 0.33 | % | | 1.44 | % | SWEPCo | | 3.39 | % | | 0.46 | % | | 1.52 | % | | 0.41 | % | | 0.21 | % | | 0.34 | % |
AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maximum | | Minimum | | Maximum | | Minimum | | Average | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
Nine Months | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
Ended | | Borrowed | | Borrowed | | Loaned | | Loaned | | Borrowed | | Loaned |
September 30, | | from AEP | | from AEP | to AEP | | to AEP | | from AEP | | to AEP |
2021 | | 0.86 | % | | 0.25 | % | | 0.86 | % | | 0.25 | % | | 0.35 | % | | 0.34 | % |
2020 | | 2.70 | % | | 0.50 | % | | 2.70 | % | | 0.50 | % | | 1.45 | % | | 1.40 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Maximum | | Minimum | | Maximum | | Minimum | | Average | | Average |
| | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate | | Interest Rate |
Nine Months | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds | | for Funds |
Ended | | Borrowed | | Borrowed | | Loaned | | Loaned | | Borrowed | | Loaned |
September 30, | | from AEP | | from AEP | to AEP | | to AEP | | from AEP | | to AEP |
2022 | | 3.39 | % | | 0.46 | % | | 3.37 | % | | 0.46 | % | | 1.56 | % | | 1.38 | % |
2021 | | 0.86 | % | | 0.25 | % | | 0.86 | % | | 0.25 | % | | 0.35 | % | | 0.34 | % |
Short-term Debt (Applies to AEP and SWEPCo)AEP)
Outstanding short-term debt was as follows:
| | | | | September 30, 2021 | | December 31, 2020 | | | | September 30, 2022 | | December 31, 2021 |
| | Outstanding | | Interest | | Outstanding | | Interest | | Outstanding | | Interest | | Outstanding | | Interest |
Company | Company | | Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) | Company | | Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) |
| | | | | (dollars in millions) | | | | | (dollars in millions) |
AEP | AEP | | Securitized Debt for Receivables (b) | | $ | 750.0 | | | 0.19 | % | | $ | 592.0 | | | 0.85 | % | AEP | | Securitized Debt for Receivables (b) | | $ | 750.0 | | | 1.16 | % | | $ | 750.0 | | | 0.19 | % |
AEP | AEP | | Commercial Paper | | 1,254.0 | | | 0.25 | % | | 1,852.3 | | | 0.29 | % | AEP | | Commercial Paper | | 1,952.3 | | | 3.38 | % | | 1,364.0 | | | 0.34 | % |
AEP | AEP | | 364-Day Term Loan | | 500.0 | | | 0.72 | % | | — | | | — | % | AEP | | Term Loan | | — | | | — | % | | 500.0 | | | 0.81 | % |
| SWEPCo | | Notes Payable | | — | | | — | % | | 35.0 | | | 2.55 | % | |
| | Total Short-term Debt | | $ | 2,504.0 | | | | | $ | 2,479.3 | | | | |
| | | | Total Short-term Debt | | $ | 2,702.3 | | | | | $ | 2,614.0 | | | |
(a)Weighted-average rate.
(b)Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Credit Facilities
For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
Securitized Accounts Receivables – AEP Credit (Applies to AEP)
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections.
AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and was amended in September 2021 to include a $125 million and a $625 million facility. The $125 million facility which expirewas renewed in September 20232022 and 2024, respectively.amended to extend the expiration date to September 2024. The $625 million facility also expires in September 2024. As of September 30, 2021,2022, the affiliated utility subsidiaries are in compliance with all requirements under the agreement.
Accounts receivable information for AEP Credit was as follows:
| | | Three Months Ended | | Nine Months Ended | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, | | September 30, | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | | 2022 | | 2021 |
| | (dollars in millions) | | (dollars in millions) |
Effective Interest Rates on Securitization of Accounts Receivable | Effective Interest Rates on Securitization of Accounts Receivable | | 0.18 | % | | 0.36 | % | | 0.19 | % | | 1.05 | % | Effective Interest Rates on Securitization of Accounts Receivable | | 2.25 | % | | 0.18 | % | | 1.16 | % | | 0.19 | % |
Net Uncollectible Accounts Receivable Written-Off | Net Uncollectible Accounts Receivable Written-Off | | $ | 7.5 | | | $ | 2.9 | | | $ | 22.6 | | | $ | 10.5 | | Net Uncollectible Accounts Receivable Written-Off | | $ | 9.5 | | | $ | 7.5 | | | $ | 23.1 | | | $ | 22.6 | |
| | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
| | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,031.3 | | | $ | 958.4 | |
Short-term – Securitized Debt of Receivables | | 750.0 | | | 592.0 | |
Delinquent Securitized Accounts Receivable | | 60.0 | | | 62.3 | |
Bad Debt Reserves Related to Securitization | | 39.8 | | | 60.0 | |
Unbilled Receivables Related to Securitization | | 224.5 | | | 296.8 | |
| | | | | | | | | | | | | | |
| | September 30, 2022 | | December 31, 2021 |
| | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,172.5 | | | $ | 995.2 | |
Short-term – Securitized Debt of Receivables | | 750.0 | | | 750.0 | |
Delinquent Securitized Accounts Receivable | | 57.4 | | | 57.9 | |
Bad Debt Reserves Related to Securitization | | 39.4 | | | 42.8 | |
Unbilled Receivables Related to Securitization | | 252.3 | | | 307.1 | |
AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due.
Securitized Accounts Receivables – AEP Credit (Applies to all Registrant Subsidiaries except AEP Texas and AEPTCo)
Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant
Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable.KPCo ceased selling accounts receivable to AEP Credit in the first quarter of 2022, based on the pending sale to Liberty. As a result, in the first quarter of 2022, KPCo recorded an allowance for uncollectible accounts on its balance sheet for those receivables no longer sold to AEP Credit. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder.
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreements were:
| Company | Company | | September 30, 2021 | | December 31, 2020 | Company | | September 30, 2022 | | December 31, 2021 |
| | | (in millions) | | | (in millions) |
APCo | APCo | | $ | 131.0 | | | $ | 136.0 | | APCo | | $ | 127.5 | | | $ | 153.1 | |
I&M | I&M | | 173.9 | | | 170.5 | | I&M | | 187.8 | | | 156.9 | |
OPCo | OPCo | | 377.3 | | | 398.8 | | OPCo | | 476.7 | | | 392.7 | |
PSO | PSO | | 147.1 | | | 85.0 | | PSO | | 188.4 | | | 114.5 | |
SWEPCo | SWEPCo | | 185.6 | | | 158.6 | | SWEPCo | | 217.0 | | | 153.0 | |
The fees paid to AEP Credit for customer accounts receivable sold were:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | Company | | 2021 (a) | | 2020 | | 2021 (a) | | 2020 | Company | | 2022 | | 2021 (a) | | 2022 | | 2021 (a) |
| | | (in millions) | | | (in millions) |
APCo | APCo | | $ | 1.3 | | | $ | 2.0 | | | $ | 3.7 | | | $ | 5.0 | | APCo | | $ | 2.8 | | | $ | 1.3 | | | $ | 5.6 | | | $ | 3.7 | |
I&M | I&M | | 2.1 | | | 3.9 | | | 5.3 | | | 9.3 | | I&M | | 2.8 | | | 2.1 | | | 6.5 | | | 5.3 | |
OPCo | OPCo | | 4.6 | | | 9.8 | | | 3.5 | | | 19.6 | | OPCo | | 7.3 | | | 4.6 | | | 22.2 | | | 3.5 | |
PSO | PSO | | 1.1 | | | 1.5 | | | 2.4 | | | 3.8 | | PSO | | 2.4 | | | 1.1 | | | 4.6 | | | 2.4 | |
SWEPCo | SWEPCo | | 1.3 | | | 2.8 | | | 4.1 | | | 6.8 | | SWEPCo | | 3.2 | | | 1.3 | | | 6.0 | | | 4.1 | |
(a)In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by the registrants.Registrants. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.
The proceeds on the sale of receivables to AEP Credit were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2021 | | 2020 | | 2021 | | 2020 |
| | (in millions) |
APCo | | $ | 342.2 | | | $ | 323.5 | | | $ | 980.6 | | | $ | 961.8 | |
I&M | | 536.8 | | | 532.3 | | | 1,478.9 | | | 1,443.6 | |
OPCo | | 668.4 | | | 666.0 | | | 1,867.5 | | | 1,793.0 | |
PSO | | 460.1 | | | 369.2 | | | 1,068.8 | | | 961.4 | |
SWEPCo | | 488.5 | | | 478.3 | | | 1,265.5 | | | 1,225.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Company | | 2022 | | 2021 | | 2022 | | 2021 |
| | (in millions) |
APCo | | $ | 360.4 | | | $ | 342.2 | | | $ | 1,114.9 | | | $ | 980.6 | |
I&M | | 558.5 | | | 536.8 | | | 1,574.3 | | | 1,478.9 | |
OPCo | | 874.1 | | | 668.4 | | | 2,284.0 | | | 1,867.5 | |
PSO | | 588.5 | | | 460.1 | | | 1,380.4 | | | 1,068.8 | |
SWEPCo | | 593.6 | | | 488.5 | | | 1,425.3 | | | 1,265.5 | |
13. PROPERTY, PLANT AND EQUIPMENT
The disclosure in this note applies to AEP, PSO and APCo.SWEPCo.
Asset Retirement Obligations
The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms, solar farms and certain coal mining facilities. The discussion below summarizes significant changes to the Registrants ARO recorded in 20212022 and should be read in conjunction with the Property, Plant and Equipment note within the 20202021 Annual Report.
In 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCoMarch 2022, PSO and SWEPCo acquired respective undivided ownership interests in the entity that owned Traverse during its development and construction. Immediately following the acquisition, PSO and SWEPCo liquidated the entity and simultaneously distributed the Traverse assets in proportion to close certain ash disposal units attheir undivided ownership interests. Traverse was placed in-service in March 2022. As a result, PSO and SWEPCo incurred additional ARO liabilities of $13 million and $15 million, respectively. See the retired Glen Lyn Station by removal“North Central Wind Energy Facilities” section of all coal combustion material. In June 2020, APCoNote 6 for additional information. Additionally, in March 2022, SWEPCo recorded a $13 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of HB 443. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increasedan increase in estimated ash disposal ARO liabilities by an additional $79 million. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. APCo is permitted to record carrying costs on the unrecovered balance ofpond closure costs at the Pirkey Plant and the Welsh Plant. In June 2022, SWEPCo recorded a weighted-average cost of capital approved by the Virginia SCC.$16 million revision due to an increase in estimated reclamation costs at Sabine. In September 2022, SWEPCo recorded a $14 million revision due to an increase in estimated landfill closure costs at Pirkey Plant.
The following is a reconciliation of the aggregate carrying amounts of ARO for AEP, PSO and APCo:SWEPCo:
| Company | Company | | ARO as of December 31, 2020 | | Accretion Expense | | Liabilities Incurred | | Liabilities Settled | | Revisions in Cash Flow Estimates | | ARO as of September 30, 2021 | Company | | ARO as of December 31, 2021 | | Accretion Expense | | Liabilities Incurred | | Liabilities Settled | | Revisions in Cash Flow Estimates | | ARO as of September 30, 2022 |
| | | (in millions) | | | (in millions) |
AEP (d)(e) | AEP (d)(e) | | $ | 2,516.7 | | | $ | 77.6 | | | $ | 17.7 | | | $ | (27.6) | | | $ | 75.1 | | | $ | 2,659.5 | | AEP (d)(e) | | $ | 2,741.7 | | | $ | 82.1 | | | $ | 37.4 | | | $ | (29.4) | | | $ | 90.9 | | | $ | 2,922.7 | |
APCo (a)(d) | | 313.1 | | | 9.9 | | | — | | | (5.8) | | | 84.7 | | | 401.9 | | |
| PSO (a)(d) | | PSO (a)(d) | | 57.6 | | | 3.0 | | | 12.8 | | | (0.6) | | | 1.9 | | | 74.7 | |
SWEPCo (a)(c)(d) | | SWEPCo (a)(c)(d) | | 222.7 | | | 8.3 | | | 15.4 | | | (16.9) | | | 48.0 | | | 277.5 | |
(a)Includes ARO related to ash disposal facilities.
(b)Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.85$1.98 billion and $1.80$1.93 billion as of September 30, 20212022 and December 31, 2020,2021, respectively.
(c)Includes ARO related to Sabine and DHLC.
(d)Includes ARO related to asbestos removal.
(e)Includes $18 million and $18 million as of September 30, 2022 and December 31, 2021, respectively, of ARO classified as Liabilities Held for Sale on the balance sheets. See “Disposition of KPCo and KTCo” section of Note 6 for additional information.
14. REVENUE FROM CONTRACTS WITH CUSTOMERS
The disclosures in this note apply to all Registrants, unless indicated otherwise.
Disaggregated Revenues from Contracts with Customers
The tables below represent AEP’s reportable segment revenues from contracts with customers, net of respective provisions for refund, by type of revenue:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 1,298.0 | | | $ | 721.9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,019.9 | |
Commercial Revenues | | 725.1 | | | 373.0 | | | — | | | — | | | — | | | — | | | 1,098.1 | |
Industrial Revenues | | 658.5 | | | 191.5 | | | — | | | — | | | — | | | (0.3) | | | 849.7 | |
Other Retail Revenues | | 54.3 | | | 15.0 | | | — | | | — | | | — | | | — | | | 69.3 | |
Total Retail Revenues | | 2,735.9 | | | 1,301.4 | | | — | | | — | | | — | | | (0.3) | | | 4,037.0 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 299.3 | | | — | | | — | | | 83.7 | | | — | | | (0.2) | | | 382.8 | |
Transmission Revenues (a) | | 120.3 | | | 162.3 | | | 424.9 | | | — | | | — | | | (392.7) | | | 314.8 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 44.3 | | | — | | | (2.5) | | | 41.8 | |
Retail, Trading and Marketing Revenues | | — | | | — | | | — | | | 482.9 | | | 2.2 | | | 0.2 | | | 485.3 | |
Total Wholesale and Competitive Retail Revenues | | 419.6 | | | 162.3 | | | 424.9 | | | 610.9 | | | 2.2 | | | (395.2) | | | 1,224.7 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 69.7 | | | 74.5 | | | (0.3) | | | 1.7 | | | 24.3 | | | (31.9) | | | 138.0 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 3,225.2 | | | 1,538.2 | | | 424.6 | | | 612.6 | | | 26.5 | | | (427.4) | | | 5,399.7 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 0.9 | | | (13.5) | | | 6.3 | | | — | | | — | | | 4.4 | | | (1.9) | |
Other Revenues (b) (d) | | 0.2 | | | 5.5 | | | — | | | 122.8 | | | 1.8 | | | (2.0) | | | 128.3 | |
Total Other Revenues | | 1.1 | | | (8.0) | | | 6.3 | | | 122.8 | | | 1.8 | | | 2.4 | | | 126.4 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 3,226.3 | | | $ | 1,530.2 | | | $ | 430.9 | | | $ | 735.4 | | | $ | 28.3 | | | $ | (425.0) | | | $ | 5,526.1 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $342 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $18 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 1,144.3 | | | $ | 598.0 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,742.3 | |
Commercial Revenues | | 618.9 | | | 279.9 | | | — | | | — | | | — | | | — | | | 898.8 | |
Industrial Revenues | | 566.0 | | | 95.2 | | | — | | | — | | | — | | | (0.1) | | | 661.1 | |
Other Retail Revenues | | 47.5 | | | 11.1 | | | — | | | — | | | — | | | — | | | 58.6 | |
Total Retail Revenues | | 2,376.7 | | | 984.2 | | | — | | | — | | | — | | | (0.1) | | | 3,360.8 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 233.8 | | | — | | | — | | | 47.8 | | | — | | | — | | | 281.6 | |
Transmission Revenues (a) | | 99.8 | | | 150.6 | | | 375.8 | | | — | | | — | | | (317.4) | | | 308.8 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 24.1 | | | — | | | (0.6) | | | 23.5 | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 397.1 | | | 0.1 | | | (3.1) | | | 394.1 | |
Total Wholesale and Competitive Retail Revenues | | 333.6 | | | 150.6 | | | 375.8 | | | 469.0 | | | 0.1 | | | (321.1) | | | 1,008.0 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 49.4 | | | 54.2 | | | 5.1 | | | 1.4 | | | 23.5 | | | (40.1) | | | 93.5 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 2,759.7 | | | 1,189.0 | | | 380.9 | | | 470.4 | | | 23.6 | | | (361.3) | | | 4,462.3 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 0.5 | | | 6.4 | | | 10.7 | | | — | | | — | | | (11.7) | | | 5.9 | |
Other Revenues (b) (d) | | (0.9) | | | 4.9 | | | — | | | 150.7 | | | 3.1 | | | (3.0) | | | 154.8 | |
Total Other Revenues | | (0.4) | | | 11.3 | | | 10.7 | | | 150.7 | | | 3.1 | | | (14.7) | | | 160.7 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 2,759.3 | | | $ | 1,200.3 | | | $ | 391.6 | | | $ | 621.1 | | | $ | 26.7 | | | $ | (376.0) | | | $ | 4,623.0 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $286 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $4 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | Three Months Ended September 30, 2020 | | Three Months Ended September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | (in millions) |
Retail Revenues: | Retail Revenues: | | Retail Revenues: | |
Residential Revenues | Residential Revenues | | $ | 1,053.3 | | | $ | 594.8 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,648.1 | | Residential Revenues | | $ | 204.0 | | | $ | — | | | $ | 360.5 | | | $ | 238.6 | | | $ | 517.9 | | | $ | 299.6 | | | $ | 285.5 | |
Commercial Revenues | Commercial Revenues | | 559.7 | | | 259.2 | | | — | | | — | | | — | | | — | | | 818.9 | | Commercial Revenues | | 107.1 | | | — | | | 161.1 | | | 154.3 | | | 266.1 | | | 153.4 | | | 182.3 | |
Industrial Revenues | Industrial Revenues | | 504.5 | | | 93.9 | | | — | | | — | | | — | | | (0.1) | | | 598.3 | | Industrial Revenues | | 35.4 | | | — | | | 163.3 | | | 155.6 | | | 156.1 | | | 98.9 | | | 108.3 | |
Other Retail Revenues | Other Retail Revenues | | 41.4 | | | 10.0 | | | — | | | — | | | — | | | — | | | 51.4 | | Other Retail Revenues | | 11.5 | | | — | | | 20.6 | | | 1.2 | | | 3.5 | | | 30.1 | | | 0.6 | |
Total Retail Revenues | Total Retail Revenues | | 2,158.9 | | | 957.9 | | | — | | | — | | | — | | | (0.1) | | | 3,116.7 | | Total Retail Revenues | | 358.0 | | | — | | | 705.5 | | | 549.7 | | | 943.6 | | | 582.0 | | | 576.7 | |
| Wholesale and Competitive Retail Revenues: | | |
Wholesale Revenues: | | Wholesale Revenues: | |
Generation Revenues(a) | Generation Revenues(a) | | 158.4 | | | — | | | — | | | 30.5 | | | — | | | — | | | 188.9 | | Generation Revenues(a) | | — | | | — | | | 107.9 | | | 126.3 | | | — | | | 9.4 | | | 87.6 | |
Transmission Revenues (a)(b) | Transmission Revenues (a)(b) | | 84.4 | | | 119.1 | | | 317.7 | | | — | | | — | | | (276.9) | | | 244.3 | | Transmission Revenues (a)(b) | | 140.8 | | | 411.7 | | | 41.5 | | | 8.8 | | | 21.5 | | | 10.2 | | | 42.3 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 15.8 | | | — | | | (0.3) | | | 15.5 | | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 447.5 | | | 0.9 | | | (24.8) | | | 423.6 | | |
Total Wholesale and Competitive Retail Revenues | | 242.8 | | | 119.1 | | | 317.7 | | | 493.8 | | | 0.9 | | | (302.0) | | | 872.3 | | |
Total Wholesale Revenues | | Total Wholesale Revenues | | 140.8 | | | 411.7 | | | 149.4 | | | 135.1 | | | 21.5 | | | 19.6 | | | 129.9 | |
| Other Revenues from Contracts with Customers (b) | | 34.1 | | | 42.8 | | | 2.4 | | | 0.7 | | | 33.9 | | | (43.7) | | | 70.2 | | |
Other Revenues from Contracts with Customers (c) | | Other Revenues from Contracts with Customers (c) | | 9.5 | | | (0.3) | | | 33.7 | | | 30.6 | | | 64.8 | | | 6.4 | | | 7.6 | |
| Total Revenues from Contracts with Customers | Total Revenues from Contracts with Customers | | 2,435.8 | | | 1,119.8 | | | 320.1 | | | 494.5 | | | 34.8 | | | (345.8) | | | 4,059.2 | | Total Revenues from Contracts with Customers | | 508.3 | | | 411.4 | | | 888.6 | | | 715.4 | | | 1,029.9 | | | 608.0 | | | 714.2 | |
| Other Revenues: | Other Revenues: | | Other Revenues: | |
Alternative Revenues (b) | | (1.0) | | | 9.3 | | | (2.2) | | | — | | | — | | | 6.6 | | | 12.7 | | |
Other Revenues (b) (d) | | — | | | 36.2 | | | — | | | (4.5) | | | (2.2) | | | (35.0) | | | (5.5) | | |
Alternative Revenues (d) | | Alternative Revenues (d) | | 0.6 | | | 7.1 | | | — | | | — | | | (14.1) | | | 0.2 | | | 3.3 | |
Other Revenues (d) | | Other Revenues (d) | | — | | | — | | | 0.3 | | | — | | | 5.5 | | | — | | | — | |
Total Other Revenues | Total Other Revenues | | (1.0) | | | 45.5 | | | (2.2) | | | (4.5) | | | (2.2) | | | (28.4) | | | 7.2 | | Total Other Revenues | | 0.6 | | | 7.1 | | | 0.3 | | | — | | | (8.6) | | | 0.2 | | | 3.3 | |
| Total Revenues | Total Revenues | | $ | 2,434.8 | | | $ | 1,165.3 | | | $ | 317.9 | | | $ | 490.0 | | | $ | 32.6 | | | $ | (374.2) | | | $ | 4,066.4 | | Total Revenues | | $ | 508.9 | | | $ | 418.5 | | | $ | 888.9 | | | $ | 715.4 | | | $ | 1,021.3 | | | $ | 608.2 | | | $ | 717.5 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission HoldcoAPCo was $246 million. The remaining affiliated amounts were immaterial.$44 million primarily related to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $339 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & MarketingI&M was $19 million.$15 million primarily related to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2021 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 172.5 | | | $ | — | | | $ | 340.1 | | | $ | 231.7 | | | $ | 425.4 | | | $ | 236.8 | | | $ | 230.9 | |
Commercial Revenues | | 89.1 | | | — | | | 146.9 | | | 143.9 | | | 190.8 | | | 120.9 | | | 145.4 | |
Industrial Revenues | | 25.4 | | | — | | | 154.8 | | | 146.8 | | | 69.8 | | | 77.1 | | | 85.4 | |
Other Retail Revenues | | 8.2 | | | — | | | 18.6 | | | 1.3 | | | 3.1 | | | 23.4 | | | 2.3 | |
Total Retail Revenues | | 295.2 | | | — | | | 660.4 | | | 523.7 | | | 689.1 | | | 458.2 | | | 464.0 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 83.7 | | | 80.2 | | | — | | | 7.2 | | | 77.1 | |
Transmission Revenues (b) | | 131.5 | | | 360.1 | | | 35.2 | | | 8.7 | | | 19.1 | | | 10.6 | | | 37.1 | |
Total Wholesale Revenues | | 131.5 | | | 360.1 | | | 118.9 | | | 88.9 | | | 19.1 | | | 17.8 | | | 114.2 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 6.8 | | | 5.0 | | | 22.5 | | | 24.2 | | | 47.3 | | | 8.3 | | | 6.1 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 433.5 | | | 365.1 | | | 801.8 | | | 636.8 | | | 755.5 | | | 484.3 | | | 584.3 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.9) | | | 11.9 | | | 2.2 | | | (1.1) | | | 7.3 | | | (0.5) | | | (0.2) | |
Other Revenues (d) | | — | | | — | | | — | | | — | | | 4.9 | | | — | | | — | |
Total Other Revenues | | (0.9) | | | 11.9 | | | 2.2 | | | (1.1) | | | 12.2 | | | (0.5) | | | (0.2) | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 432.6 | | | $ | 377.0 | | | $ | 804.0 | | | $ | 635.7 | | | $ | 767.7 | | | $ | 483.8 | | | $ | 584.1 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $30 million primarily relatingrelated to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $281 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $17 million primarily relatingrelated to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
| | | Three Months Ended September 30, 2020 | | Nine Months Ended September 30, 2022 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) | | (in millions) |
Retail Revenues: | Retail Revenues: | | Retail Revenues: | |
Residential Revenues | Residential Revenues | | $ | 165.3 | | | $ | — | | | $ | 324.2 | | | $ | 222.6 | | | $ | 429.4 | | | $ | 195.8 | | | $ | 219.4 | | Residential Revenues | | $ | 3,428.1 | | | $ | 1,884.1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 5,312.2 | |
Commercial Revenues | Commercial Revenues | | 78.0 | | | — | | | 138.4 | | | 135.8 | | | 181.2 | | | 94.4 | | | 135.0 | | Commercial Revenues | | 1,922.8 | | | 994.4 | | | — | | | — | | | — | | | — | | | 2,917.2 | |
Industrial Revenues(b) | Industrial Revenues(b) | | 24.9 | | | — | | | 139.4 | | | 139.7 | | | 69.1 | | | 55.0 | | | 83.8 | | Industrial Revenues(b) | | 1,863.3 | | | 487.3 | | | — | | | — | | | — | | | (0.7) | | | 2,349.9 | |
Other Retail Revenues | Other Retail Revenues | | 6.9 | | | — | | | 17.6 | | | 1.6 | | | 3.1 | | | 18.4 | | | 2.3 | | Other Retail Revenues | | 154.6 | | | 39.4 | | | — | | | — | | | — | | | — | | | 194.0 | |
Total Retail Revenues | Total Retail Revenues | | 275.1 | | | — | | | 619.6 | | | 499.7 | | | 682.8 | | | 363.6 | | | 440.5 | | Total Retail Revenues | | 7,368.8 | | | 3,405.2 | | | — | | | — | | | — | | | (0.7) | | | 10,773.3 | |
| Wholesale Revenues: | | |
Wholesale and Competitive Retail Revenues: | | Wholesale and Competitive Retail Revenues: | |
Generation Revenues (a)(b) | Generation Revenues (a)(b) | | — | | | — | | | 70.3 | | | 61.5 | | | — | | | 5.8 | | | 42.3 | | Generation Revenues (a)(b) | | 674.8 | | | — | | | — | | | 207.0 | | | — | | | (0.1) | | | 881.7 | |
Transmission Revenues (b)(a) | Transmission Revenues (b)(a) | | 101.8 | | | 305.7 | | | 30.8 | | | 7.4 | | | 17.2 | | | 8.5 | | | 28.7 | | Transmission Revenues (b)(a) | | 334.4 | | | 482.1 | | | 1,261.0 | | | — | | | — | | | (1,086.5) | | | 991.0 | |
Total Wholesale Revenues | | 101.8 | | | 305.7 | | | 101.1 | | | 68.9 | | | 17.2 | | | 14.3 | | | 71.0 | | |
Renewable Generation Revenues (b) | | Renewable Generation Revenues (b) | | — | | | — | | | — | | | 104.9 | | | — | | | (6.2) | | | 98.7 | |
Retail, Trading and Marketing Revenues (c) | | Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 1,280.0 | | | 6.7 | | | (11.1) | | | 1,275.6 | |
Total Wholesale and Competitive Retail Revenues | | Total Wholesale and Competitive Retail Revenues | | 1,009.2 | | | 482.1 | | | 1,261.0 | | | 1,591.9 | | | 6.7 | | | (1,103.9) | | | 3,247.0 | |
| Other Revenues from Contracts with Customers (c) | | 15.2 | | | 3.0 | | | 16.1 | | | 17.7 | | | 27.6 | | | 4.8 | | | 5.6 | | |
Other Revenues from Contracts with Customers (d) | | Other Revenues from Contracts with Customers (d) | | 180.5 | | | 194.2 | | | (0.3) | | | 11.9 | | | 59.1 | | | (71.6) | | | 373.8 | |
| Total Revenues from Contracts with Customers | Total Revenues from Contracts with Customers | | 392.1 | | | 308.7 | | | 736.8 | | | 586.3 | | | 727.6 | | | 382.7 | | | 517.1 | | Total Revenues from Contracts with Customers | | 8,558.5 | | | 4,081.5 | | | 1,260.7 | | | 1,603.8 | | | 65.8 | | | (1,176.2) | | | 14,394.1 | |
| Other Revenues: | Other Revenues: | | Other Revenues: | |
Alternative Revenues (d) | | (0.7) | | | (4.6) | | | (1.1) | | | 0.4 | | | 10.0 | | | (0.5) | | | 0.2 | | |
Other Revenues (d) | | 40.6 | | | — | | | — | | | — | | | 3.4 | | | — | | | — | | |
Alternative Revenues (b) | | Alternative Revenues (b) | | 3.4 | | | (21.5) | | | (39.6) | | | — | | | — | | | (7.4) | | | (65.1) | |
Other Revenues (b) (e) | | Other Revenues (b) (e) | | 0.3 | | | 18.6 | | | — | | | 410.5 | | | 6.9 | | | (6.9) | | | 429.4 | |
| Total Other Revenues | Total Other Revenues | | 39.9 | | | (4.6) | | | (1.1) | | | 0.4 | | | 13.4 | | | (0.5) | | | 0.2 | | Total Other Revenues | | 3.7 | | | (2.9) | | | (39.6) | | | 410.5 | | | 6.9 | | | (14.3) | | | 364.3 | |
| Total Revenues | Total Revenues | | $ | 432.0 | | | $ | 304.1 | | | $ | 735.7 | | | $ | 586.7 | | | $ | 741.0 | | | $ | 382.2 | | | $ | 517.3 | | Total Revenues | | $ | 8,562.2 | | | $ | 4,078.6 | | | $ | 1,221.1 | | | $ | 2,014.3 | | | $ | 72.7 | | | $ | (1,190.5) | | | $ | 14,758.4 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCoAEP Transmission Holdco was $28 million primarily relating to the PPA with KGPCo.$1 billion. The affiliated revenue for Vertically Integrated Utilities was $120 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $243 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&MGeneration & Marketing was $15 million primarily relating to barging, urea transloading and other transportation services.$11 million. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Corporate and Other was $36 million. The remaining affiliated amounts were immaterial.
(e)Generation & Marketing includes economic hedge activity.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2021 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 3,016.2 | | | $ | 1,641.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,657.4 | |
Commercial Revenues | | 1,642.0 | | | 804.1 | | | — | | | — | | | — | | | — | | | 2,446.1 | |
Industrial Revenues | | 1,602.5 | | | 283.8 | | | — | | | — | | | — | | | (0.5) | | | 1,885.8 | |
Other Retail Revenues | | 125.9 | | | 32.4 | | | — | | | — | | | — | | | — | | | 158.3 | |
Total Retail Revenues | | 6,386.6 | | | 2,761.5 | | | — | | | — | | | — | | | (0.5) | | | 9,147.6 | |
| | | | | | | | | | | | | | |
Wholesale and Competitive Retail Revenues: | | | | | | | | | | | | | | |
Generation Revenues | | 757.1 | | | — | | | — | | | 119.4 | | | — | | | — | | | 876.5 | |
Transmission Revenues (a) | | 267.3 | | | 420.7 | | | 1,092.1 | | | — | | | — | | | (901.5) | | | 878.6 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 66.7 | | | — | | | (1.7) | | | 65.0 | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 1,325.6 | | | 0.6 | | | (48.5) | | | 1,277.7 | |
Total Wholesale and Competitive Retail Revenues | | 1,024.4 | | | 420.7 | | | 1,092.1 | | | 1,511.7 | | | 0.6 | | | (951.7) | | | 3,097.8 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (b) | | 136.1 | | | 149.3 | | | 12.5 | | | 4.9 | | | 46.1 | | | (87.9) | | | 261.0 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 7,547.1 | | | 3,331.5 | | | 1,104.6 | | | 1,516.6 | | | 46.7 | | | (1,040.1) | | | 12,506.4 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (b) | | 10.7 | | | 46.1 | | | 42.2 | | | — | | | — | | | (63.5) | | | 35.5 | |
Other Revenues (b) (d) | | (0.6) | | | 14.2 | | | — | | | 175.3 | | | 8.4 | | | (8.6) | | | 188.7 | |
Total Other Revenues | | 10.1 | | | 60.3 | | | 42.2 | | | 175.3 | | | 8.4 | | | (72.1) | | | 224.2 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 7,557.2 | | | $ | 3,391.8 | | | $ | 1,146.8 | | | $ | 1,691.9 | | | $ | 55.1 | | | $ | (1,112.2) | | | $ | 12,730.6 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission Holdco was $835 million. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & Marketing was $49 million. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
| | | Nine Months Ended September 30, 2020 | | Nine Months Ended September 30, 2022 |
| | Vertically Integrated Utilities | | Transmission and Distribution Utilities | | AEP Transmission Holdco | | Generation & Marketing | | Corporate and Other | | Reconciling Adjustments | | AEP Consolidated | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) | | (in millions) |
Retail Revenues: | Retail Revenues: | | | | Retail Revenues: | |
Residential Revenues | Residential Revenues | | $ | 2,789.1 | | | $ | 1,610.6 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,399.7 | | Residential Revenues | | $ | 520.8 | | | $ | — | | | $ | 1,131.7 | | | $ | 665.6 | | | $ | 1,363.3 | | | $ | 650.7 | | | $ | 650.0 | |
Commercial Revenues | Commercial Revenues | | 1,523.6 | | | 792.4 | | | — | | | — | | | — | | | — | | | 2,316.0 | | Commercial Revenues | | 312.6 | | | — | | | 467.6 | | | 419.5 | | | 681.9 | | | 372.1 | | | 458.8 | |
Industrial Revenues(d) | Industrial Revenues(d) | | 1,508.7 | | | 290.4 | | | — | | | — | | | — | | | (0.5) | | | 1,798.6 | | Industrial Revenues(d) | | 102.6 | | | — | | | 479.0 | | | 452.1 | | | 384.8 | | | 270.0 | | | 290.1 | |
Other Retail Revenues | Other Retail Revenues | | 118.2 | | | 32.1 | | | — | | | — | | | — | | | — | | | 150.3 | | Other Retail Revenues | | 29.2 | | | — | | | 61.4 | | | 3.7 | | | 10.2 | | | 77.1 | | | 7.4 | |
Total Retail Revenues | Total Retail Revenues | | 5,939.6 | | | 2,725.5 | | | — | | | — | | | — | | | (0.5) | | | 8,664.6 | | Total Retail Revenues | | 965.2 | | | — | | | 2,139.7 | | | 1,540.9 | | | 2,440.2 | | | 1,369.9 | | | 1,406.3 | |
| Wholesale and Competitive Retail Revenues: | | |
Wholesale Revenues: | | Wholesale Revenues: | |
Generation Revenues(a) | Generation Revenues(a) | | 447.4 | | | — | | | — | | | 106.1 | | | — | | | — | | | 553.5 | | Generation Revenues(a) | | — | | | — | | | 227.6 | | | 310.9 | | | — | | | 19.2 | | | 206.2 | |
Transmission Revenues (a)(b) | Transmission Revenues (a)(b) | | 248.4 | | | 341.6 | | | 937.7 | | | — | | | — | | | (741.7) | | | 786.0 | | Transmission Revenues (a)(b) | | 417.7 | | | 1,218.1 | | | 123.4 | | | 26.3 | | | 64.4 | | | 28.9 | | | 116.8 | |
Renewable Generation Revenues (b) | | — | | | — | | | — | | | 50.7 | | | — | | | (1.2) | | | 49.5 | | |
Retail, Trading and Marketing Revenues (c) | | — | | | — | | | — | | | 1,133.8 | | | (5.7) | | | (80.7) | | | 1,047.4 | | |
Total Wholesale and Competitive Retail Revenues | | 695.8 | | | 341.6 | | | 937.7 | | | 1,290.6 | | | (5.7) | | | (823.6) | | | 2,436.4 | | |
Total Wholesale Revenues | | Total Wholesale Revenues | | 417.7 | | | 1,218.1 | | | 351.0 | | | 337.2 | | | 64.4 | | | 48.1 | | | 323.0 | |
| Other Revenues from Contracts with Customers (b) | | 124.1 | | | 112.3 | | | 17.5 | | | 1.7 | | | 84.4 | | | (115.7) | | | 224.3 | | |
Other Revenues from Contracts with Customers (c) | | Other Revenues from Contracts with Customers (c) | | 24.4 | | | (0.4) | | | 78.6 | | | 86.3 | | | 169.6 | | | 21.4 | | | 18.9 | |
| Total Revenues from Contracts with Customers | Total Revenues from Contracts with Customers | | 6,759.5 | | | 3,179.4 | | | 955.2 | | | 1,292.3 | | | 78.7 | | | (939.8) | | | 11,325.3 | | Total Revenues from Contracts with Customers | | 1,407.3 | | | 1,217.7 | | | 2,569.3 | | | 1,964.4 | | | 2,674.2 | | | 1,439.4 | | | 1,748.2 | |
| Other Revenues: | Other Revenues: | | Other Revenues: | |
Alternative Revenues (b) | | (6.0) | | | 49.2 | | | (77.4) | | | — | | | — | | | 3.5 | | | (30.7) | | |
Other Revenues (b) (d) | | — | | | 78.1 | | | — | | | 13.2 | | | (6.7) | | | (71.3) | | | 13.3 | | |
Alternative Revenues (d) | | Alternative Revenues (d) | | (2.9) | | | (34.4) | | | 0.1 | | | 7.3 | | | (18.6) | | | (0.7) | | | 0.7 | |
Other Revenues (d) | | Other Revenues (d) | | — | | | — | | | 0.4 | | | (0.1) | | | 18.6 | | | — | | | — | |
Total Other Revenues | Total Other Revenues | | (6.0) | | | 127.3 | | | (77.4) | | | 13.2 | | | (6.7) | | | (67.8) | | | (17.4) | | Total Other Revenues | | (2.9) | | | (34.4) | | | 0.5 | | | 7.2 | | | — | | | (0.7) | | | 0.7 | |
| Total Revenues | Total Revenues | | $ | 6,753.5 | | | $ | 3,306.7 | | | $ | 877.8 | | | $ | 1,305.5 | | | $ | 72.0 | | | $ | (1,007.6) | | | $ | 11,307.9 | | Total Revenues | | $ | 1,404.4 | | | $ | 1,183.3 | | | $ | 2,569.8 | | | $ | 1,971.6 | | | $ | 2,674.2 | | | $ | 1,438.7 | | | $ | 1,748.9 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEP Transmission HoldcoAPCo was $725 million.$122 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $992 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for Generation & MarketingI&M was $81 million.$44 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Generation & Marketing includes economic hedge activity.
Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2021 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 423.7 | | | $ | — | | | $ | 1,025.0 | | | $ | 624.4 | | | $ | 1,217.5 | | | $ | 516.4 | | | $ | 547.1 | |
Commercial Revenues | | 265.2 | | | — | | | 409.5 | | | 384.5 | | | 538.9 | | | 286.8 | | | 385.4 | |
Industrial Revenues | | 81.6 | | | — | | | 433.4 | | | 418.9 | | | 202.2 | | | 202.1 | | | 247.1 | |
Other Retail Revenues | | 23.1 | | | — | | | 51.7 | | | 3.9 | | | 9.4 | | | 58.2 | | | 7.2 | |
Total Retail Revenues | | 793.6 | | | — | | | 1,919.6 | | | 1,431.7 | | | 1,968.0 | | | 1,063.5 | | | 1,186.8 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 231.2 | | | 248.1 | | | — | | | 6.8 | | | 326.2 | |
Transmission Revenues (b) | | 364.5 | | | 1,045.2 | | | 94.1 | | | 25.3 | | | 56.2 | | | 28.8 | | | 94.5 | |
Total Wholesale Revenues | | 364.5 | | | 1,045.2 | | | 325.3 | | | 273.4 | | | 56.2 | | | 35.6 | | | 420.7 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 35.4 | | | 12.5 | | | 43.6 | | | 81.9 | | | 113.8 | | | 24.8 | | | 17.7 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 1,193.5 | | | 1,057.7 | | | 2,288.5 | | | 1,787.0 | | | 2,138.0 | | | 1,123.9 | | | 1,625.2 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | 1.8 | | | 46.5 | | | 9.5 | | | (3.0) | | | 44.3 | | | 0.5 | | | 5.1 | |
Other Revenues (d) | | — | | | — | | | — | | | — | | | 14.2 | | | — | | | — | |
Total Other Revenues | | 1.8 | | | 46.5 | | | 9.5 | | | (3.0) | | | 58.5 | | | 0.5 | | | 5.1 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 1,195.3 | | | $ | 1,104.2 | | | $ | 2,298.0 | | | $ | 1,784.0 | | | $ | 2,196.5 | | | $ | 1,124.4 | | | $ | 1,630.3 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $90 million primarily relating to the PPA with KGPCo.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $823 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $46 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2020 |
| | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in millions) |
Retail Revenues: | | | | | | | | | | | | | | |
Residential Revenues | | $ | 447.8 | | | $ | — | | | $ | 954.4 | | | $ | 610.8 | | | $ | 1,162.6 | | | $ | 463.5 | | | $ | 498.7 | |
Commercial Revenues | | 285.2 | | | — | | | 390.6 | | | 376.0 | | | 507.3 | | | 247.8 | | | 351.2 | |
Industrial Revenues | | 91.4 | | | — | | | 415.0 | | | 408.2 | | | 199.1 | | | 170.8 | | | 245.9 | |
Other Retail Revenues | | 22.3 | | | — | | | 50.9 | | | 5.0 | | | 9.8 | | | 51.2 | | | 6.6 | |
Total Retail Revenues | | 846.7 | | | — | | | 1,810.9 | | | 1,400.0 | | | 1,878.8 | | | 933.3 | | | 1,102.4 | |
| | | | | | | | | | | | | | |
Wholesale Revenues: | | | | | | | | | | | | | | |
Generation Revenues (a) | | — | | | — | | | 185.3 | | | 215.5 | | | — | | | 9.9 | | | 106.7 | |
Transmission Revenues (b) | | 290.4 | | | 902.6 | | | 91.5 | | | 22.1 | | | 51.1 | | | 20.2 | | | 87.5 | |
Total Wholesale Revenues | | 290.4 | | | 902.6 | | | 276.8 | | | 237.6 | | | 51.1 | | | 30.1 | | | 194.2 | |
| | | | | | | | | | | | | | |
Other Revenues from Contracts with Customers (c) | | 33.4 | | | 17.5 | | | 46.8 | | | 60.6 | | | 78.9 | | | 23.2 | | | 21.1 | |
| | | | | | | | | | | | | | |
Total Revenues from Contracts with Customers | | 1,170.5 | | | 920.1 | | | 2,134.5 | | | 1,698.2 | | | 2,008.8 | | | 986.6 | | | 1,317.7 | |
| | | | | | | | | | | | | | |
Other Revenues: | | | | | | | | | | | | | | |
Alternative Revenues (d) | | (0.3) | | | (82.3) | | | (11.9) | | | 5.4 | | | 49.6 | | | 1.5 | | | 0.5 | |
Other Revenues (d) | | 86.9 | | | — | | | — | | | — | | | 13.3 | | | — | | | — | |
Total Other Revenues | | 86.6 | | | (82.3) | | | (11.9) | | | 5.4 | | | 62.9 | | | 1.5 | | | 0.5 | |
| | | | | | | | | | | | | | |
Total Revenues | | $ | 1,257.1 | | | $ | 837.8 | | | $ | 2,122.6 | | | $ | 1,703.6 | | | $ | 2,071.7 | | | $ | 988.1 | | | $ | 1,318.2 | |
(a)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $85 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.
(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for AEPTCo was $715 million. The remaining affiliated amounts were immaterial.
(c)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for I&M was $49 million primarily relating to barging, urea transloading and other transportation services. The remaining affiliated amounts were immaterial.
(d)Amounts include affiliated and nonaffiliated revenues.
Fixed Performance Obligations
The following table represents the Registrants’ remaining fixed performance obligations satisfied over time as of September 30, 2021.2022. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The Registrant Subsidiaries amounts shown in the table below include affiliated and nonaffiliated revenues.
| Company | Company | | 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total | Company | | 2022 | | 2023-2024 | | 2025-2026 | | After 2026 | | Total |
| | | (in millions) | | | (in millions) |
AEP | AEP | | $ | 314.9 | | | $ | 199.3 | | | $ | 160.3 | | | $ | 161.5 | | | $ | 836.0 | | AEP | | $ | 318.7 | | | $ | 172.1 | | | $ | 157.8 | | | $ | 96.9 | | | $ | 745.5 | |
AEP Texas | AEP Texas | | 132.7 | | | — | | | — | | | — | | | 132.7 | | AEP Texas | | 145.8 | | | — | | | — | | | — | | | 145.8 | |
AEPTCo | AEPTCo | | 331.7 | | | — | | | — | | | — | | | 331.7 | | AEPTCo | | 369.4 | | | — | | | — | | | — | | | 369.4 | |
APCo | APCo | | 44.9 | | | 34.5 | | | 26.6 | | | 11.6 | | | 117.6 | | APCo | | 50.1 | | | 33.7 | | | 26.6 | | | 11.5 | | | 121.9 | |
I&M | I&M | | 10.0 | | | 11.5 | | | 8.8 | | | 4.5 | | | 34.8 | | I&M | | 9.7 | | | 13.6 | | | 9.2 | | | 4.5 | | | 37.0 | |
OPCo | OPCo | | 22.2 | | | 10.1 | | | — | | | — | | | 32.3 | | OPCo | | 19.2 | | | 3.4 | | | — | | | — | | | 22.6 | |
PSO | PSO | | 3.5 | | | — | | | — | | | — | | | 3.5 | | PSO | | 3.4 | | | — | | | — | | | — | | | 3.4 | |
SWEPCo | SWEPCo | | 10.1 | | | — | | | — | | | — | | | 10.1 | | SWEPCo | | 10.9 | | | — | | | — | | | — | | | 10.9 | |
Contract Assets and Liabilities
Contract assets are recognized when the Registrants have a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. The Registrants did not have material contract assets as of September 30, 20212022 and December 31, 2020.2021.
When the Registrants receive consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. The Registrants’ contract liabilities typically arise from services provided under joint use agreements for utility poles. The Registrants did not have material contract liabilities as of September 30, 20212022 and December 31, 2020.2021.
Accounts Receivable from Contracts with Customers
Accounts receivable from contracts with customers are presented on the Registrant Subsidiaries’ balance sheets within the Accounts Receivable - Customers line item. The Registrant Subsidiaries’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Accounts Receivable - Customers were not material as of September 30, 20212022 and December 31, 2020.2021. See “Securitized Accounts Receivable - AEP Credit” section of Note 12 for additional information.
The following table represents the amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable - Affiliated Companies on the Registrant Subsidiaries’ balance sheets:
| Company | Company | | September 30, 2021 | | December 31, 2020 | Company | | September 30, 2022 | | December 31, 2021 |
| | | (in millions) | | | (in millions) |
AEP Texas | | AEP Texas | | $ | — | | | $ | 0.4 | |
AEPTCo | AEPTCo | | $ | 96.4 | | | $ | 81.0 | | AEPTCo | | 110.6 | | | 95.5 | |
APCo | APCo | | 64.1 | | | 52.7 | | APCo | | 65.8 | | | 117.8 | |
I&M | I&M | | 24.6 | | | 34.8 | | I&M | | 51.1 | | | 61.2 | |
OPCo | OPCo | | 44.5 | | | 45.9 | | OPCo | | 61.5 | | | 51.7 | |
PSO | PSO | | 17.7 | | | 7.8 | | PSO | | 36.8 | | | 18.8 | |
SWEPCo | SWEPCo | | 19.9 | | | 11.2 | | SWEPCo | | 20.2 | | | 24.7 | |
15. SUBSEQUENT EVENTS
The disclosure in this note applies to AEP and AEPTCo.
Disposition of KPCo and KTCo
In October 2021, AEP entered into a Stock Purchase Agreement to sell KPCo and KTCo to Liberty Utilities Co., a subsidiary of Algonquin Power & Utilities Corp. (Liberty), for approximately a $2.85 billion enterprise value. The sale is subject to regulatory approvals from the FERC, the KPSC, clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and clearance from the Committee on Foreign Investment in the United States.
KPCo currently operates and owns a 50% interest in the 1,560 MW coal-fired Mitchell Power Plant (Mitchell Plant) with the remaining 50% owned by WPCo. The Stock Purchase Agreement is further contingent upon approval by the KPSC, WVPSC and FERC of a new proposed Mitchell Plant Operations and Maintenance Agreement and Mitchell Plant Ownership Agreement between KPCo and WPCo pursuant to which WPCo will replace KPCo as the operator of the Mitchell Plant and KPCo employees at the Mitchell Plant will become employees of WPCo at closing of the transaction. Under the proposed Ownership Agreement, WPCo is obligated to purchase KPCo’s 50% interest in the Mitchell Plant on December 31, 2028 unless KPCo and WPCo have agreed to retire the Mitchell Plant earlier or, absent such agreement, if WPCo elects prior to December 31, 2027 to retire the Mitchell Plant on December 31, 2028. The Ownership Agreement provides that the purchase price for KPCo’s 50% ownership interest in the Mitchell Plant will be determined through the mutual agreement of WPCo and KPCo (subject to approval from the KPSC and WVPSC) or through a fair market valuation determination conducted by independent appraisals if KPCo and WPCo are unable to reach agreement as to the purchase price.
The sale is expected to close in the second quarter of 2022 with Liberty acquiring the assets and assuming the liabilities of KPCo and KTCo, excluding pension and other post-retirement benefit plan assets and liabilities. AEP expects to provide customary transition services to Liberty for a period of time after closing of the transaction.
AEP expects to receive approximately $1.45 billion in cash, net of taxes and transaction fees.
The major classes of KPCo and KTCo’s assets and liabilities as presented on the balance sheets of AEP and AEPTCo as of September 30, 2021 are shown in the table below.
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| | September 30, 2021 |
| | AEP | | AEPTCo |
| | (in millions) |
Assets: | | | | |
Accounts Receivable and Accrued Unbilled Revenues | | $ | 24.7 | | | $ | 1.6 | |
Fuel, Materials and Supplies | | 26.5 | | | — | |
Property, Plant and Equipment, Net | | 2,264.6 | | | 164.5 | |
Regulatory Assets | | 501.7 | | | — | |
Other Classes of Assets that are not Major | | 43.8 | | | 0.3 | |
Total Assets | | $ | 2,861.3 | | | $ | 166.4 | |
| | | | |
Liabilities: | | | | |
Accounts Payable | | $ | 51.2 | | | $ | 1.5 | |
Long-term Debt Due Within One Year | | 125.0 | | | — | |
Customer Deposits | | 31.9 | | | — | |
Deferred Income Taxes | | 448.3 | | | 14.9 | |
Long-term Debt | | 978.0 | | | — | |
Regulatory Liabilities and Deferred Investment Tax Credits | | 146.5 | | | 7.5 | |
Other Classes of Liabilities that are not Major | | 93.2 | | | 4.2 | |
Total Liabilities | | $ | 1,874.1 | | | $ | 28.1 | |
CONTROLS AND PROCEDURES
During the third quarter of 2021,2022, management, including the principal executive officer and principal financial officer of each of the Registrants, evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. As of September 30, 2021,2022, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.
There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 20212022 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 5 incorporated herein by reference.
Item 1A. Risk Factors
The Annual Report on Form 10-K for the year ended December 31, 20202021 includes a detailed discussion of risk factors. As of September 30, 2021,2022, the risk factors appearing in AEP’s 20202021 Annual Report are supplemented and updated as follows:
The rate of taxes imposed on AEPSupply chain disruptions and inflation could change.negatively impact operations and corporate strategy. (Applies to all Registrants)
AEP is subject to income taxation at the federal levelAEP’s operations and by certain states and municipalities. In determining AEP’s income tax liability for these jurisdictions, management monitors changes to the applicable tax laws and related regulations. While management believes it is in compliance with current prevailing laws, one or more taxing jurisdictions could seek to impose incremental or new taxesbusiness plans depend on the company. In addition, asglobal supply chain to procure the equipment, materials and other resources necessary to build and provide services in a resultsafe and reliable manner. The delivery of components, materials, equipment and other resources that are critical to AEP’s business operations and corporate strategy has been restricted by the most recent presidentialcurrent domestic and congressional electionsglobal supply chain upheaval. This has resulted in the shortage of critical items. International tensions, including the ramifications of regional conflict, could further exacerbate the global supply chain upheaval. These disruptions and shortages could adversely impact business operations and corporate strategy. The constraints in the supply chain could restrict the availability and delay the construction, maintenance or repair of items that are needed to support normal operations or are required to execute AEP’s corporate strategy for continued capital investment in utility equipment. These disruptions and constraints could reduce future net income and cash flows and possibly harm AEP’s financial condition.
Supply chain disruptions have contributed to higher prices of components, materials, equipment and other needed commodities and these inflationary increases may continue in the future. The economy in the United States therehas encountered a material level of inflation and that has contributed to increased uncertainty in the outlook of near-term economic activity, including whether inflation will continue and at what rate. AEP typically recovers increases in capital expenses from customers through rates in regulated jurisdictions. Failure to recover increased capital costs could reduce future net income and cash flows and possibly harm AEP’s financial condition. Increases in inflation raises costs for labor, materials and services, and failure to secure these on reasonable terms may adversely impact AEP’s financial condition.
Physical attacks or hostile cyber intrusions could severely impair operations, lead to the disclosure of confidentialinformation and damage AEP’s reputation.(Applies to all Registrants)
AEP and its regulated utility businesses face physical security and cybersecurity risks as the owner-operators of generation, transmission and/or distribution facilities and as participants in commodities trading. AEP and its regulated utility businesses own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run these facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or AEP operations could view these computer systems, software or networks as targets for cyber-attack. The Federal government has notified the owners and operators of critical infrastructure, such as AEP, that the conflict between Russia and Ukraine has increased the likelihood of a cyber-attack on such systems. In addition, the electric utility business requires the collection of sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.
A security breach of AEP or its regulated utility businesses’ physical assets or information systems, interconnected entities in RTOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system. AEP and its regulated utility businesses could be significant changes in tax lawsubject to financial harm associated with ransomware theft or inappropriate release of certain types of information, including sensitive customer, vendor, employee, trading or other confidential data. A successful cyber-attack on the systems that control generation, transmission, distribution or other assets could severely disrupt business operations, preventing service to customers or collection of revenues. The breach of certain business systems could affect the ability to correctly record, process and regulations thatreport financial information. A major cyber incident could result in additional federal income taxes being imposedsignificant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to AEP’s reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. AEP and its third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the AEP System, there has been no material impact on AEP. Any adverse developments inbusiness or operations from these lawsattacks. However, AEP cannot guarantee that security efforts will detect or regulations, including legislative changes, judicial holdingsprevent breaches, operational incidents, or administrative interpretations, couldother breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material and adverse effect on financial condition and results of operations.in the future.
Failure to attract and retain an appropriately qualified workforceThe IRA could harm resultschange the rate of operations.taxes imposed on AEP. (Applies to all Registrants)
Certain events, suchOn August 16, 2022, President Biden signed H.R. 5376 into law, commonly known as the Inflation Reduction Act of 2022 or IRA. Most notably this budget reconciliation legislation creates a 15% minimum tax on adjusted financial statement income (Corporate Alternative Minimum Tax or CAMT), extends and increases the value of PTCs and ITCs, adds a nuclear and clean hydrogen PTC, an aging workforce without appropriate replacements, employee reaction to comply with potential COVID-19 vaccination mandates, mismatch of skillsetenergy storage ITC and allows the sale or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges include potential higher rates of existing employee departures, lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, safety costs and costs of compliance with COVID-19 vaccination or testing mandates, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledgetax credits to third parties for cash. Additional guidance on the tax provisions in the IRA is expected from the Treasury and expertisethe IRS. The regulatory treatment of the impacts of this legislation will also be subject to the new employees,discretion of the FERC and state public utility commissions. Any adverse development in this legislation, including guidance from Treasury and the IRS or theunfavorable regulatory treatment, could reduce future availability and cost of contract labor may adversely affect the ability to manage and operate the business. If AEP is unable to successfully attract and retain an appropriately qualified workforce, future net income and cash flows may be reduced.and impact financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Mine Safety Disclosures
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, a wholly-owned lignite mining subsidiary of SWEPCo, is subject to the provisions of the Mine Act.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC under the Mine Act for the quarter ended September 30, 2021.2022.
Item 5. Other Information
None.
Item 6. Exhibits
The documents designated with an (*) below have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.
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Exhibit | | Description | | Previously Filed as Exhibit to: |
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AEPTCo‡APCo‡ File No. 333-2171431-3457 | | |
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4 | | Company Order and Officer’s Certificate between AEP Transmission Company, LLCAPCo and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 4, 20211, 2022 establishing terms of the 2.75%4.50% Senior Notes, Series N,BB, due 20512032. | | |
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OPCo‡ File No.1-6543 | | |
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4 | | Company Order and Officer’s Certificate between Ohio Power Company and The Bank of New York Mellon Trust Company, N.A. as Trustee dated September 9, 2021 establishing terms of the 2.90% Senior Notes, Series R, due 2051 | | |
PSO‡ File No. 0-343 | | |
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4 | | Tenth Supplemental Indenture between Public Service Company of Oklahoma and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 1, 2021 establishing terms of the 2.20% Senior Notes, Series J, due 2031 and the 3.15% Senior Notes Series K, due 2051 | | |
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The exhibits designated with an (X) in the table below are being filed on behalf of the Registrants.
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Exhibit | | Description | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
4 | | Company Order and Officer’s Certificate between American Electric Power Company, Inc. and The Bank of New York Mellon Trust Company, N.A. as Trustee dated August 3, 2021 establishing terms of the 1.80% Senior Notes, Series 2021A due 2028 | | | | | | | | | | | | | | | | |
10 | | Amendment to Stock Purchase Agreement by anddated September 29, 2022 among American Electric Power Company, Inc., AEP, Transmission Company, LLCAEPTCo and Liberty Utilities Co. dated as of October 26, 2021 | | | | | | | | | | | | | | | | |
31(a) | | Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | | | | | | | | | |
31(b) | | Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | | | | | | | | | | | | | | | |
32(a) | | Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | | | | | | | | | | | | | | | | |
32(b) | | Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | | | | | | | | | | | | | | | | |
95 | | Mine Safety Disclosures | | | | | | | | | | | | | | | | |
101.INS | | XBRL Instance Document | | The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. |
101.SCH | | XBRL Taxonomy Extension Schema | | X | | X | | X | | X | | X | | X | | X | | X |
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Exhibit | | Description | | AEP | | AEP Texas | | AEPTCo | | APCo | | I&M | | OPCo | | PSO | | SWEPCo |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
101.LAB | | XBRL Taxonomy Extension Label Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | X | | X | | X | | X | | X | | X | | X | | X |
104 | | Cover Page Interactive Data File | | Formatted as Inline XBRL and contained in Exhibit 101. |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
AEP TEXAS INC.
AEP TRANSMISSION COMPANY, LLC
APPALACHIAN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/ Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: October 28, 202127, 2022